Edgar Filing: EL PASO ELECTRIC CO /TX/

Since 1999
(a)

Authorized
Shares

Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at December 31, 2012

EE 2012 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, 2012



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, 2012, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,313,087,454 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2013, there were 40,193,854 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 2013 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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DEFINITIONS

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



Abbreviations, Acronyms or Defined Terms		Terms

ANPP Participation Agreement		Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS		Arizona Public Service Company
ASU		Accounting Standards Updates
Company		El Paso Electric Company
DOE		United States Department of Energy
El Paso		City of El Paso, Texas
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fort Bliss		Fort Bliss the United States Army post next to El Paso, Texas
Four Corners		Four Corners Generating Station
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MW		Megawatt(s)
MWh		Megawatt-hour(s)
NERC		North American Electric Reliability Corporation
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
TNP		Texas-New Mexico Power Company



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TABLE OF CONTENTS




Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	14
1B	Unresolved Staff Comments	19
2	Properties	19
3	Legal Proceedings	19
4	Mine Safety Disclosures	19


	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
6	Selected Financial Data	22
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
7A	Quantitative and Qualitative Disclosures About Market Risk	39
8	Financial Statements and Supplementary Data	41
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	92
9A	Controls and Procedures	92
9B	Other Information	92

	PART III
10	Directors, Executive Officers and Corporate Governance	93
11	Executive Compensation	93
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
13	Certain Relationships and Related Transactions, and Director Independence	93
14	Principal Accounting Fees and Services	93

	PART IV
15	Exhibits and Financial Statement Schedules	94



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FORWARD-LOOKING STATEMENTS

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


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

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


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


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


•	reductions in output at generation plants operated by us,


•	unscheduled outages including outages at Palo Verde,


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


•	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,


•	cuts in military spending that reduce demand for our services from military customers,



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•	political, legislative, judicial and regulatory developments,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,


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


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


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


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


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


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


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


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings “Risk Factors” and “Management’s Discussion and Analysis” “–Summary of Critical Accounting Policies and Estimates” and “–Liquidity and Capital Resources.” This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.



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PART I


Item 1.	Business

General

El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a net dependable generating capability of approximately 1,765 MW. For the year ended December 31, 2012, the Company’s energy sources consisted of approximately 46% nuclear fuel, 32% natural gas, 6% coal, 16% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 384,000 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, 2012). 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, oil refineries, two large universities, steel production and copper refining facilities.

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, 2013, the Company had approximately 1,000 employees, 40% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the internet site is not incorporated into this document by reference.

Facilities

As of December 31, 2012, the Company’s net dependable generating capability of 1,765 MW consists of the following:



Station	Primary Fuel Type	Company's Share of Net Dependable Generating Capability * (MW)	Company Ownership Interest		Location
Palo Verde Station	Nuclear	633	15.8	%	Wintersburg, Arizona
Newman Power Station	Natural Gas	732	100	%	El Paso, Texas
Rio Grande Power Station	Natural Gas	229	100	%	Sunland Park, New Mexico
Four Corners Station (Units 4 and 5)	Coal	108	7	%	Fruitland, New Mexico
Copper Power Station	Natural Gas	62	100	%	El Paso, Texas
Hueco Mountain Wind Ranch	Wind	1	100	%	Hudspeth County, Texas
Total		1,765

____________________

* During summer peak period.

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Palo Verde Station

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


•	License Extension. In 2011, the NRC renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively.

•

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2011, the Palo Verde Participants approved the 2010 Palo Verde decommissioning study (the “2010 Study”), which reflected the extension of the operating license, and estimated that the Company must fund approximately $357.4 million (stated in 2010 dollars) to cover its share of decommissioning costs. At December 31, 2013, the Company's decommissioning trust fund had a balance of $187.1 million. Although the 2010 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 “Waste Act”), 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, but to date has not done so. In 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the DOE’s acceptance of spent fuel. In 2010, the court awarded APS and the other Palo Verde Participants approximately $30 million in damages, of which the Company received $4.8 million. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second lawsuit against the DOE, seeking to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.

The DOE had planned to meet its disposal obligations through a permanent geologic repository at Yucca Mountain, Nevada. However, legal proceedings in a variety of jurisdictions, as well as regulatory challenges, have delayed the approval and implementation of this plan. The Company cannot predict when spent fuel shipments to the DOE will commence. APS and the Company believe that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the current term of its operating license, however the Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde, which may be recoverable from the DOE.

•

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, which caused significant damage to the Fukushima Daiichi Nuclear Power Station, the NRC launched a two-pronged review of U.S. nuclear power plant safety. 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 also requested information pertaining to re-evaluations of seismic and flooding hazards, communications, and staffing during events affecting multiple reactors at a site. Palo Verde has budgeted $14 million, total project, in modifications for the 2013 capital budget relating to the NRC requirements. Until further action is taken by the NRC as a result of this event, the Company cannot predict any additional financial or operational impacts on Palo Verde.

•

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 $55.7 million, with an annual payment limitation of approximately $8.3 million. The Palo Verde Participants also maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.

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Fossil-Fueled Plants

The Newman Power Station consists of three steam-electric generating units and two combined cycle generating units. In 2012 the net dependable capability at Newman Power Station was reduced by 20 MW to reflect the exclusion of the duct burners for dependable operation on the Newman Unit 4 combined cycle generating unit. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.

The Company's Rio Grande Power Station consists of three steam-electric generating units which operate on natural gas. Construction has begun on Rio Grande Unit 9 to add an aeroderivative unit with a net dependable summer peak period generating capacity of 87 MW that should achieve commercial operation by May 2013.

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 Comers 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's Copper Power Station consists of a combustion turbine used primarily to meet peak demand.

Hueco Mountain Wind Ranch

The Company’s Hueco Mountain Wind Ranch currently consists of two wind turbines with a total capacity of 1.32 MW of which a portion, currently 10%, is used as net capability for resource planning purposes.

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.

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	%
West Mesa-Arroyo Line (2)	202	345	100	%
Greenlee-Hidalgo-Luna-Newman Line (3)
Greenlee-Hidalgo	60	345	40	%
Hidalgo-Luna	50	345	57	%
Luna-Newman	86	345	100	%
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

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Substation located near Las Cruces, New Mexico.


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

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


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

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

Environmental Matters

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

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

Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's ("EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions since 2009. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, such appellate court in August 2012 also vacated the EPA’s proposed replacement, called the Cross-State Air Pollution Rule (“CSAPR”). The EPA is expected to propose a CSAPR replacement rule, which if finalized and upheld, would also replace CAIR. The timing and substance of any final CAIR replacement is currently unknown and until promulgated and upheld, the Company remains subject to CAIR. The annual reconciliation to comply with CAIR is due by March 31 of the following year.The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):



Compliance Year	Amount
2010		$	370
2011		90
2012		37

National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria emissions considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO") and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO2. In December 2012, the EPA strengthened the NAAQS for fine PM, and it is likely to propose more stringent ozone NAAQS in 2013. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and consolidated financial results.

Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil- and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will have up to three (and some cases, four) years to comply. Information from the Four Corners plant operator, APS, indicates that APS believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards; however, further testing and evaluation are planned.

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Other Laws and Regulations. In addition, Four Corners, is, or may in the future be, required to comply with various other environmental laws and regulations and involved in various other legal proceedings related to such laws and regulations, which compliance and proceedings could result in increased costs to us. For example, Four Corners will be required to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plant, the costs of which could be material.

Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide. In particular, the U.S. Congress is expected to consider legislation to restrict or regulate GHG emissions in the next few years. In the past few years, the EPA began using the CAA to limit carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which the Company is subject, as well as the EPA’s 2010 so-called Tailoring Rule which rule could impose significant obligation and costs on power plant owners and operators. During the second term of the Obama Administration, the EPA is expected to propose further regulations targeting GHG emissions, including from existing power plants at some point in the future. In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHGs, any of which could have a material adverse effect on the Company's business, financial condition, reputation or results of operations.

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

Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters from or of Four Corners. Since July 2011, the U.S. Department of Justice ("DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going.

Similar to other utilities in the western half of the U.S., the Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPSs. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. Earthjustice filed their response briefs on May 16, 2012. APS filed reply briefs on June 22, 2012. Utility Air Regulatory Group filed an amicus brief, and plaintiffs were allowed until July 23, 2012 to respond to that amicus brief. In November 2012, the parties filed a joint motion to stay the proceedings to enable settlement discussions, and the motion was granted staying the case until March 2013. The Company is unable to predict the outcome of this litigation.

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Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.

The Company’s estimated cash construction costs for 2013 through 2017 are approximately $1.2 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) (in millions)			By Function (in millions)
2013	$	264	Generation (1)(2)	$	572
2014	326		Transmission	176
2015	222		Distribution	312
2016	209		General	140
2017	179
Total	$	1,200	Total	$	1,200

__________________________


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

(2)

$325 million has been allocated for new generating capacity including $10 million to complete Rio Grande Unit 9 in 2013. Included in this amount is $98 million to complete construction of two 88 MW gas-fired LMS-100 units that are scheduled to come on line in 2014 and 2015, and $138 million for two additional 88 MW LMS-100 units scheduled to come on line in 2016 and 2017. In addition, $62 million of common costs associated with the development of the new Montana generating station are included in these amounts. Also included is $17 million for a combined cycle unit scheduled to come on line in 2021, $44 million for other local generation, $37 million for the Four Corners Station and $166 million for the Palo Verde Station.

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Energy Sources

General

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



	Years Ended December 31,
Power Source	2012		2011		2010
Nuclear	46	%	45	%	45	%
Natural gas	32		30		27
Coal	6		6		6
Purchased power	16		19		22
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 PUCT and the NMPRC. See “Regulation – Texas Regulatory Matters” and “– New Mexico Regulatory Matters.”

Nuclear Fuel

The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"); the enrichment of uranium hexafluoride ("enrichment services"); the fabrication of fuel assemblies ("fabrication services"); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel.

Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2016, 95% of its requirements in 2017 and 80% of its requirements in 2018. The participants have also contracted for all of Palo Verde's conversion services through 2016 and 90% of its requirements in 2017-2018, all of Palo Verde's enrichment services through 2020 and all of Palo Verde's fuel assembly fabrication services through 2016.

Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust (“RGRT”), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $110 million aggregate principal amount borrowed through senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and amounts borrowed under the revolving credit facility (the “RCF”).

The Company maintains the RCF for the financing of nuclear fuel and for working capital and general corporate purposes. The RCF has a term ending September 2016. On March 29, 2012, the Company increased the aggregate unsecured borrowing available under the RCF from $200 million to $300 million. The total amount borrowed for nuclear fuel by RGRT at December 31, 2012 was $132.2 million of which $22.2 million had been borrowed under the RCF, and $110 million was borrowed through the senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to the Company as fuel is consumed and recovered from customers through fuel recovery charges.

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 2012, 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 2013. Interstate gas is delivered under a base firm transportation contract. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the Newman and Rio Grande Power Stations. The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for the Newman and Rio Grande Power Stations.

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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.

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. The Four Corners coal contract expires in mid-2016.

On December 19, 2012, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which full ownership of BNCC would be sold to the Navajo Nation. BHP Billiton would be retained by BNCC under contract as the mine manager and operator until July 2016. A new coal supply contract, which extends the term beyond July 2016, is being negotiated by the Navajo Nation and APS on behalf of the other Four Corners participants. Any new coal supply contract or revisions to the current contract are subject to the approval of all the Four Corners participants.

As a result of this proposed change in ownership of BNCC, the participants are negotiating a new coal supply contract and the endorsement of the transfer of ownership of the stock of BNCC to a new Navajo Nation commercial enterprise to be established by the Navajo Nation Tribal Council is being contemplated. The decision of the Tribal Council is currently expected to occur in the second quarter of 2013.

Purchased Power

The Company has a Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC (“Freeport”) which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to 125 MW at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2013. The contract was approved by the FERC and continues through December 31, 2021.

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

The Company entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 (10 MW) and SunEdison 2 (12 MW) which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.

Other purchases of shorter duration were made during 2012 to supplement the Company's generation resources during planned and unplanned outages and for economic reasons as well as to supply off‑system sales.

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Operating Statistics



	Years Ended December 31,
	2012			2011			2010
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	234,095		$	234,086		$	217,615
Commercial and industrial, small	188,014			196,093			188,390
Commercial and industrial, large	42,041			45,407			43,844
Sales to public authorities	96,132			94,370			86,460
Total retail base revenues	560,282			569,956			536,309
Wholesale:
Sales for resale	2,318			2,122			1,943
Total non-fuel base revenues	562,600			572,078			538,252
Fuel revenues:
Recovered from customers during the period	130,193			145,130			170,588
Under (over) collection of fuel	(18,539		)	13,917			(35,408		)
New Mexico fuel in base rates	74,154			73,454			71,876
Total fuel revenues	185,808			232,501			207,056
Off-system sales:
Fuel cost	62,481			74,736			93,516
Shared margins	9,191			3,883			6,114
Retained margins	1,098			(560		)	5,687
Total off-system sales	72,770			78,059			105,317
Other	31,703			35,375			26,626
Total operating revenues	$	852,881		$	918,013		$	877,251
Number of customers (end of year):
Residential	341,682			337,659			334,729
Commercial and industrial, small	37,712			37,942			37,202
Commercial and industrial, large	50			49			50
Other	4,654			4,596			4,841
Total	384,098			380,246			376,822
Average annual kWh use per residential customer	7,767			7,832			7,560
Energy supplied, net, kWh (in thousands):
Generated	9,261,643			8,936,776			8,465,659
Purchased and interchanged	1,768,810			2,135,124			2,420,869
Total	11,030,453			11,071,900			10,886,528
Energy sales, kWh (in thousands):
Retail:
Residential	2,648,348			2,633,390			2,508,834
Commercial and industrial, small	2,366,541			2,352,218			2,295,537
Commercial and industrial, large	1,082,973			1,096,040			1,087,413
Sales to public authorities	1,617,606			1,579,565			1,542,389
Total retail	7,715,468			7,661,213			7,434,173
Wholesale:
Sales for resale	64,266			62,656			53,637
Off-system sales	2,614,132			2,687,631			2,822,732
Total wholesale	2,678,398			2,750,287			2,876,369
Total energy sales	10,393,866			10,411,500			10,310,542
Losses and Company use	636,587			660,400			575,986
Total	11,030,453			11,071,900			10,886,528
Native system:
Peak load, kW	1,688,000			1,714,000			1,616,000
Net dependable generating capability for peak, kW	1,765,000			1,785,000			1,643,000
Total system:
Peak load, kW (1)	1,979,000			1,967,000			1,889,000
Net dependable generating capability for peak, kW	1,765,000			1,785,000			1,643,000


(1)	Includes spot sales and net losses of 291,000 kW, 253,000 kW and 273,000 kW for 2012, 2011 and 2010, respectively.

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Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012.

Under the terms of the settlement, among other things, the Company agreed to:


•	A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;


•	Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;


•	Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and


•	A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.

As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011. The Company will file a 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.

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a fuel cost recovery rule ("Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. In 2010, the Company received approval to implement a formula to determine its fuel factor which adjusts natural gas and purchased power to reflect natural gas futures prices. 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.

During 2012, the Company filed the following petition with the PUCT to refund recent fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest:

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund Amount Authorized (In thousands)

40622

August 3, 2012

September 28, 2012

January 2011- June 2012

September 2012

6,600

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The Company filed the following petition in 2012 with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:



Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor	Effective Billing Month
40302	April 12, 2012	April 25, 2012	(18.5)%	May 2012

Generation CCN Filing. On May 2, 2012, the Company filed a petition with the PUCT requesting a CCN to construct a new generating facility to be located at a new plant site, the Montana Power Station, in east El Paso. The new facility will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines, which will be powered by natural gas. The first unit is scheduled to become operational in 2014. On December 13, 2012, the PUCT issued a Final Order approving the requested CCN.

The Company has also filed two air permit applications for the Montana Power Station. One application was filed with the Texas Commission on Environmental Quality ("TCEQ") and a contested hearing on the merits of the application is scheduled for May 1, 2013, before the State Office of Administrative Hearings in Austin, Texas. Several parties, representing affected individuals as defined by TCEQ, have requested status in the hearing. The second air permit application is an EPA greenhouse permit application which remains under review. A final permit is expected from the EPA by August 2013 if there is no appeal. While the Company believes that the Montana Power Station complies with all air regulations, it cannot predict the final outcome of these applications.

Energy Efficiency Cost Recovery Factor ("EECRF"). On April 30, 2012, the Company filed an application to revise its EECRF and to establish revised energy efficiency goals and cost caps, pursuant to the Public Utility Regulatory Act ("PURA") Section 39.905. On September 20, 2012, the PUCT approved a unanimous settlement resolving all issues. The settlement allows the Company to recover $5.5 million in energy efficiency costs, revised the Company’s demand and energy goals and granted the Company’s request to increase its 2013 EECRF effective with billings in January 2013.

Military Base Discount Recovery Factor ("MBDRF"). On July 16, 2012, the Company filed a petition to revise its MBDRF. On November 16, 2012, the PUCT approved a unanimous stipulation and settlement, with the City of El Paso and Staff, which provides for the surcharge to be increased from 0.936% to 1.055% of customer bills. The revised MBDRF is designed to recover estimated discounts and the recovery of past under-recoveries spread over two years, totaling $4.6 million and is effective with December 2012 billings.

Other Required Approvals. The Company has obtained all other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by 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.

Generation CCN Filing. On May 2, 2012, the Company filed a petition with the NMPRC requesting a CCN to construct a new generation facility to be located at a new plant site, the Montana Power Station, in east El Paso. The NMPRC approved the CCN on January 23, 2013.

2012 Annual Procurement Plan Pursuant to the Renewable Energy Act. On June 29, 2012, the Company filed its application for approval of its 2012 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On December 11, 2012, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2013 and 2014 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2013 and 2014 to be met with a combination of previously approved resources and excused the Company from a requirement to make-up a deficiency in the "other" diversity requirement for 2011 and from meeting the "other" diversity requirement for the 2013 and 2014 compliance years. Costs for purchases of renewable energy delivered to the Company are recovered through the New Mexico Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") and purchases of renewable energy credits are recovered through base rates.

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("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs in the Company's New Mexico service territory. The Company also seeks approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. The hearing is scheduled to begin March 14, 2013 and a final order is expected by the end of May 2013.

Other Required Approvals. The Company has obtained all 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 Changes 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.

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

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

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

Sales for Resale

The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to 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 RGEC.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2013.

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 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	July 1, 2005 - August 1, 2010	3.25%
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) The additional fee of 0.75% is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.

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Military Installations

The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and Fort Bliss. The Company’s sales to the military installations represent approximately 5% of annual retail revenues. The Company signed a contract with Fort Bliss in October 2008 under which Fort Bliss takes retail electric service from the Company. The contract with Fort Bliss expired in 2010 and the Company is serving Fort Bliss under the applicable Texas tariffs. In April 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. The contract with White Sands expired in 2009 and 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.

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Executive Officers of the Registrant

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 25, 2013, were as follows:



Name	Age	Current Position and Business Experience
Thomas V. Shockley III	67	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.
David G. Carpenter	57	Senior Vice President and Chief Financial Officer since August 2009; Vice President – Regulatory Services and Controller from September 2008 to August 2009; Vice President – Corporate Planning and Controller from August 2005 to September 2008.
Mary E. Kipp	45	Senior Vice President, General Counsel and Chief Compliance Officer since June 2010; Vice President – Legal and Chief Compliance Officer from December 2009 to June 2010; Assistant General Counsel and Director of FERC Compliance from December 2007 to December 2009; Senior Enforcement Attorney – FERC from January 2004 to December 2007.
Rocky R. Miracle	60	Senior Vice President – Corporate Planning and Development since August 2009; Vice President – Corporate Planning from September 2008 to August 2009; Director of Business Operations Support – Texas Operations for American Electric Power Services Corporation from August 2004 to August 2008.
Hector R. Puente	56	Senior Vice President and Chief Operations Officer since June 2012; Senior Vice President – Operations from May 2011 to May 2012; Vice President – Transmission and Distribution from January 2006 to May 2011.
Nathan T. Hirschi	49	Vice President and Controller since March 2010; Vice President – Special Projects from December 2009 to February 2010; Partner for KPMG LLP from October 2003 to April 2009.

Item 1A. Risk Factors

Like other companies in our industry, our consolidated 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 consolidated 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 January 2010.

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

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

The construction of our next generating plant addition, Rio Grande Unit 9, will add an aeroderivative unit with a generating capacity of 87 MW. It should reach commercial operation by May 2013. In addition, we have received approval from both the PUCT and NMPRC of the CCN to construct the first two units of the Montana Power Station, a new plant site, which will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines. We have risk related to recovering all costs associated with the completion of the construction of Rio Grande Unit 9 and other new units.

In 2012, we issued $150 million in aggregate principal amount of 3.30% Senior Notes, due December 15, 2022. The 3.30% Senior Notes along with our revolving credit facility could help fund the construction of the Montana Power Station and other new units. The costs of financing and constructing these units will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the PUCT or 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 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.

Continuing 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. 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. 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 36% of our available net generating capacity and provided approximately 46% of our energy requirements for the twelve months ended December 31, 2012. Palo Verde comprises approximately 32% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 92.3% and 90.7% in the twelve months ended December 31, 2012 and 2011, 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, or other causes.

We May Not Be Able to Recover All of Our Fuel Expenses from Customers

In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 09-00171-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

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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. Our most recent rate filing at the PUCT (Docket No. 40094) included a request to reconcile $356.6 million of fuel expense for the period July 1, 2009 through September 30, 2011. However, as part of the settlement in the case, we agreed to withdraw our fuel reconciliation request. We agreed to file a 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 our next rate case, if earlier. In the event that recovery of fuel and purchased power expenses is denied in 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 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, 2012 and 2011, the Company had a net over-collection balance of $4.6 million and a net under-collection balance of $7.0 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 addition, we are seeking to extend the lives of these plants. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. 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 consolidated 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 Public Utility Regulatory Act ("PURA") in June 2011. PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if they are achieved at all. There is substantial 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.

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Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Consolidated Financial Results

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

Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and/or consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. For example, the EPA has issued in the recent past various final and proposed regulations regarding air emissions from our operations as well as the rest of the utility sector, including the CSAPR and the GHG New Source Performance Standard ("NSPS") for Electric Generating Units. If these regulations become finalized and survive legal and Congressional challenges, the cost to us to comply could adversely affect our operations and consolidated financial results.

Cost of compliance with environmental laws and regulations also adds uncertainty to the timing and costs of our future generation additions. We have filed two air permit applications for the Montana Power Station, our proposed new generation facility in far east El Paso, with the TCEQ and the EPA. A contested hearing on the merits of the application filed with the TCEQ is scheduled for May 1, 2013, before the State Office of Administrative Hearings in Austin, Texas. Several parties, representing affected individuals as defined by TCEQ, have requested status in the hearing. The application filed with the EPA remains under review. While we believe that the Montana Power Station complies with all air regulations, we cannot predict the final outcome of these applications.

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

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

The Company emits GHGs through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, the EPA began regulating GHG emissions from certain stationary sources, such as power plants, in January 2011. On March 27, 2012, EPA released its proposed NSPS for new and modified electric generating units. The potential impact of these rules on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.

It is not currently possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any such regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.

Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Information Technology 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 information technology infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, maintenance downtimes, system failures, natural disasters 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

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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, including the Improving Critical Infrastructure Cybersecurity executive order and the proposed Cyber Intelligence Sharing and Protection Act, could lead to increased regulatory compliance costs, require us to make capital expenditures or otherwise harm our business.

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Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The principal properties of the Company are described in Item 1, “Business,” and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, 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 2014. The Company has several other leases for office and parking facilities which expire within the next five 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, to the extent that the Company has been able to reach a conclusion as to its ultimate liability, it believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

See “Environmental Matters” and “Regulation” for discussion of the effects of government legislation and regulation on the Company.


Item 4.	Mine Safety Disclosures

Not Applicable.

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PART II


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

The Company’s common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “EE.” The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the New York Stock Exchange, 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)
2011
First Quarter	$	30.68	$	26.65	$	30.40	$	—
Second Quarter	32.40		29.09		32.30		0.22
Third Quarter	35.65		29.82		32.09		0.22
Fourth Quarter	35.71		30.29		34.64		0.22
2012
First Quarter	$	35.34	$	31.58	$	32.49	$	0.22
Second Quarter	33.65		29.17		33.16		0.25
Third Quarter	34.93		32.45		34.25		0.25
Fourth Quarter	35.01		30.15		31.91		0.25

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Performance Graph

The following graph compares the performance of the Company’s Common Stock to the performance of Edison Electric Institute’s Index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2007 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, as reflected in the graph.



	12/31/2007	12/31/2008	12/31/2009	12/31/2010	12/31/2011	12/31/2012
EE	100	71	79	108	137	130
EEI Index	100	74	82	88	105	108
NYSE Composite	100	59	74	82	77	87

As of January 31, 2013, there were 2,760 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 $38.9 million in cash dividends during the twelve months ended December 31, 2012. On January 17, 2013, our Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year. We are currently targeting a payout ratio of approximately 45%. 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, 2012 under the 2011 Plan. As of December 31, 2012, 393,816 shares remain eligible for repurchase under the 2011 Plan.

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

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Item 6.Selected Financial Data

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



	Years Ended December 31,
	2012		2011		2010		2009		2008
Operating revenues	$	852,881	$	918,013	$	877,251	$	827,996	$	1,038,930
Operating income	$	168,658	$	190,803	$	168,962	$	133,165	$	145,736
Income before extraordinary items	$	90,846	$	103,539	$	90,317	$	66,933	$	77,621
Extraordinary gain, net of tax (a)	$	—	$	—	$	10,286	$	—	$	—
Net income	$	90,846	$	103,539	$	100,603	$	66,933	$	77,621
Basic earnings per share:
Income before extraordinary items	$	2.27	$	2.49	$	2.08	$	1.50	$	1.73
Extraordinary gain (a)	$	—	$	—	$	0.24	$	—	$	—
Net income	$	2.27	$	2.49	$	2.32	$	1.50	$	1.73
Weighted average number of shares outstanding	39,974,022		41,349,883		43,129,735		44,524,146		44,777,765
Diluted earnings per share:
Income before extraordinary items	$	2.26	$	2.48	$	2.07	$	1.50	$	1.72
Extraordinary gain (a)	$	—	$	—	$	0.24	$	—	$	—
Net income	$	2.26	$	2.48	$	2.31	$	1.50	$	1.72
Weighted average number of shares and dilutive
potential shares outstanding	40,055,581		41,587,059		43,294,419		44,595,067		44,930,109
Dividends declared per share of common stock	$	0.97	$	0.66	$	—	$	—	$	—
Cash additions to utility property, plant and equipment	$	202,387	$	178,041	$	169,966	$	209,974	$	198,711
Total assets	$	2,669,050	$	2,396,851	$	2,364,766	$	2,226,152	$	2,069,083
Long-term debt and financing obligations, net of
current portion	$	999,535	$	816,497	$	849,745	$	804,975	$	809,718
Common stock equity	$	824,999	$	760,251	$	810,375	$	722,729	$	694,229

______________________


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

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

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

Summary of Critical Accounting Policies and Estimates

Our consolidated financial statements have been prepared in conformity with Generally Accepted Accounting Principles ("GAAP"). Note A to the consolidated 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, 2012, we had recorded regulatory assets currently subject to recovery in future rates of approximately $101.6 million and regulatory liabilities of approximately $22.2 million as discussed in greater detail in Note D of the Notes to the Consolidated 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 and 3 and associated common areas. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. Decommissioning costs will be adjusted prospectively for future changes in estimated decommissioning costs and when actual costs are incurred to decommission the plant. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the plant increase, we could be required to increase our funding to the decommissioning trust accounts. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning.

Future Pension and Other Postretirement Obligations

Our obligations to retirees under various benefit plans are recorded as a liability on the consolidated 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 consolidated balance sheets.

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we

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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 consolidated financial statements.

Overview

The following is an overview of our results of operations for the years ended December 31, 2012, 2011 and 2010. Income before extraordinary item for the years ended December 31, 2012, 2011 and 2010 is shown below:



	Years Ended December 31,
	2012		2011		2010
Income before extraordinary item (in thousands)	$	90,846	$	103,539	$	90,317
Basic earnings per share before extraordinary item	2.27		2.49		2.08

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The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the calendar years ended 2012 and 2011, 2011 and 2010, and 2010 and 2009 (in thousands):



	2012				2011				2010
Prior year December 31 income before extraordinary item	$	103,539			$	90,317			$	66,933
Change in (net of tax):
Increased (decreased) retail non-fuel base revenues	(6,385		)	(a)	21,198			(b)	33,395			(c)
Increased administrative and general expense	(5,730		)	(d)	(1,342		)		(3,502		)	(d)
Increased (decreased) deregulated Palo Verde Unit 3 revenues	(3,282		)	(e)	(808		)		1,235
Increased (decreased) transmission wheeling revenue	(1,785		)		3,197			(f)	1,446
Increased operations and maintenance at fossil fuel generating plants	(1,532		)		(3,725		)	(g)	(1,120		)
Increased taxes other than income taxes	(1,242		)		(678		)		(2,830		)	(h)
Decreased (increased) customer care expense	2,192			(i)	(2,069		)	(j)	(2,445		)	(k)
Decreased (increased) depreciation and amortization	1,831			(l)	(202		)		(3,821		)	(m)
Increased (decreased) AFUDC	1,745			(n)	(3,804		)	(o)	1,909
Increased (decreased) off-system sales margins retained	1,095				(3,935		)	(p)	(3,224		)	(q)
Decreased Palo Verde operations and maintenance expense	867				640				2,753			(r)
Decreased (increased) transmission and distribution operations and maintenance expense	433				(1,964		)	(s)	1,200
Elimination of Medicare Part D tax benefit	—				4,787			(t)	(4,787		)	(t)
Other	(900		)		1,927				3,175
Current year December 31 income before extraordinary item	$	90,846			$	103,539			$	90,317

______________________

(a)

Retail non-fuel base revenues decreased in 2012 compared to 2011 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customer due to a reduction in non-fuel base rates in Texas effective May 1, 2012, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates.


(b)	Retail non-fuel base revenues increased in 2011 compared to 2010 primarily due to a 3.1% increase in kWh sales to retail customers reflecting hotter summer weather with higher non-fuel base summer rates and 1.4% growth in the average number of retail customers served in 2011.


(c)	Retail non-fuel base revenues increased in 2010 compared to 2009 primarily due to new non-fuel base rates in New Mexico and Texas to recover capital investments to meet customer growth and a 4.4% increase in retail kWh sales.


(d)	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.


(e)	Deregulated Palo Verde Unit 3 revenues in 2012 reflect lower proxy market prices associated with the decline in natural gas prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in March and April 2012, and an increase in the costs of nuclear fuel burned.


(f)	Transmission revenues increased in 2011 primarily due to a settlement agreement with Tucson Electric Power Company resolving a transmission dispute that resulted in a one-time adjustment to income of $3.9 million, pre-tax and annual revenue of $1.1 million per year.


(g)	Operations and maintenance at gas-fired fuel generating stations increased in 2011 largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades.


(h)	Taxes other than income taxes increased in 2010 compared to 2009 due to revenue-related taxes and increased property taxes.


(i)	Customer care expense decreased in 2012 compared to 2011 primarily due to a decrease in the provision for uncollectible accounts reflecting improved collection efforts.


(j)	Customer care expense increased in 2011 compared to 2010 primarily due to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs.


(k)	Customer care expense increased in 2010 compared to 2009 primarily due to the transition to our new customer billing system and increased uncollectible customer accounts.


(l)	Depreciation and amortization expense decreased in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation

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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.


(m)	Depreciation and amortization expense increased in 2010 compared to 2009 due to increased depreciable plant balances and increased depreciation rates.


(n)	AFUDC (allowance for funds used during construction) increased primarily due to higher balances of construction work in progress subject to AFUDC primarily reflecting construction work in progress on Rio Grande Unit 9 and the Montana Power Station in 2012.


(o)	AFUDC decreased in 2011 compared to 2010 primarily due to lower balances of construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant addition in April 2011.


(p)	Off-system sales margins decreased in 2011 compared to 2010 primarily due to lower average market prices for power and an increase in sharing of off-system sales margins with customers from 25% to 90% effective in July 2010.


(q)	Off-system sales margins decreased in 2010 compared to 2009 due to increased sharing of off-system sales margins with customers from 25% to 90% effective July 1, 2010 consistent with prior rate agreements in Texas and New Mexico.


(r)	Palo Verde non-fuel operations and maintenance expense decreased in 2010 compared to 2009 primarily due to decreased maintenance costs at Units 2 and 3 as the result of reduced costs for scheduled refueling outages.


(s)	Transmission and distribution operations and maintenance expense increased in 2011 compared to 2010 primarily due to increased wheeling expense, a reliability study for the North American Electric Reliability Corporation, and an increase in payroll costs.


(t)	A one-time charge to income tax expense was incurred in 2010 to recognize a change in tax law enacted in the Patient Protection and Affordable Care Act to eliminate the tax benefit related to the Medicare Part D subsidies with no comparable tax expense in 2011.

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Historical Results of Operations

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

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale (which are wholesale sales within our service territory) accounted for less than 1% of revenues.

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:



	Twelve Months Ended December 31,
	2012		2011		2010
Residential	42	%	41	%	41	%
Commercial and industrial, small	34		34		35
Commercial and industrial, large	7		8		8
Sales to public authorities	17		17		16
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 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:



	Years Ended December 31,
	2012		2011		2010
January 1 to March 31	19	%	18	%	21	%
April 1 to June 30	27		27		24
July 1 to September 30	33		34		33
October 1 to December 31	21		21		22
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 2012, 2011 and 2010.



	2012	2011	2010	10-year Average
Heating degree days	2,009	2,402	2,273	2,228
Cooling degree days	2,876	3,135	2,738	2,633

Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in 2012 and 1.4% in 2011. See the tables presented on pages 30 and 31 which provide detail on the average number of retail customers and the related revenues and kWh sales.

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Retail non-fuel base revenues. The rate structure effective July 1, 2010 through April 30, 2012 in Texas was based on the final order in PUCT Docket No. 37690 which approved a settlement that called for an annual increase of $17.15 million in non-fuel base rates. On April 17, 2012, the City council (the “Council”) of El Paso, Texas approved the settlement of our 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094 and on April 26, 2012, the administrative law judge issued an order implementing the settlement rates as temporary rates effective May 1, 2012. The PUCT approved the settlement on May 18, 2012. Under the terms of the settlement, among other things, we agreed to a reduction in our current non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes.

Retail non-fuel base revenues decreased by $9.7 million or 1.7% for the twelve months ended December 31, 2012 when compared to the same period in 2011. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 4.1% and 7.4%, respectively, reflecting the reduction in our non-fuel base rates as stipulated in PUCT Docket No. 40094. In addition, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sale to large commercial and industrial customer decreased 1.2%. KWh sales to small commercial and industrial customers increased 0.6% primarily due to the 0.8% increase in the average number of customers served. KWh sales to residential customers increased 0.6% due to the 1.4% increase in the average number of customers served despite significantly milder weather in 2012 compared to 2011. KWh sales to public authorities increased 2.4% and non-fuel base revenues from public authorities increased 1.9%.

Retail non-fuel base revenues increased by $33.6 million, or 6.3% for the twelve months ended December 31, 2011 when compared to the same period in 2010. The increase was primarily due to a 3.1% increase in kWh sales to retail customers, reflecting hotter summer weather with higher non-fuel base summer rates, and 1.4% growth in the average number of retail customers served. During the twelve months ended December 31, 2011, cooling degree days were 14% above the same period in 2010 and 20% above the 10-year average. KWh sales to residential customers and small commercial and industrial customers increased 5.0% and 2.5%, respectively, during the twelve months ended December 31, 2011 compared to the same period in 2010. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates.

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

We over-recovered fuel costs by $18.5 million in the twelve months ended December 31, 2012. In the twelve months ended December 31, 2011 we under-recovered fuel costs by $13.9 million and in the twelve months ended December 31, 2010, we over-recovered fuel costs by $35.4 million. Refunds of $6.9 million, $12.0 million and $34.8 million were returned to our Texas customers in the twelve months ended December 31, 2012, 2011 and 2010, respectively. At December 31, 2012, we had a net fuel over-recovery balance of $4.6 million, including $2.3 million in Texas and $2.3 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2013.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. Prior to July 1, 2010, we shared 25% of off-system sales margins with customers and retained 75% of off-system sales margins through June 30, 2010 pursuant to rate agreements in prior years. We are sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract which was effective April 1, 2008.

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.

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The table below shows MWhs, sales revenue, fuel costs, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2012, 2011 and 2010 (in thousands except for MWhs).



	Twelve Months Ended December 31,
	2012		2011			2010
MWh sales	2,614,132		2,687,631			2,822,732
Sales revenues	$	72,770	$	78,059		$	105,317
Fuel cost	$	62,481	$	74,736		$	93,516
Total margins	$	10,289	$	3,323		$	11,801
Retained margins	$	1,098	$	(560	)	$	5,687

Off-system sales revenues decreased $5.3 million or 6.8% for the twelve months ended December 31, 2012 when compared to 2011 as a result of lower average market prices for power and a 2.7% decline in MWh sales. For the twelve months ended December 31, 2012, retained margins increased $1.7 million when compared to the same period in 2011 primarily due to the negative impacts in 2011 of power purchases required for system reliability when key generation and transmission facilities were either out of service or were threatened to be out of service. Off-system sales revenues decreased $27.3 million, or 25.9% for the twelve months ended December 31, 2011 when compared to 2010 as a result of lower average market prices for power and a 4.8% decline in MWh sales. For the twelve months ended December 31, 2011, retained margins decreased $6.2 million when compared to the same period in 2010. Off-system margins were negatively affected by lower costs of natural gas which impact the average market prices in the wholesale power markets. Off-system sales margins were also negatively impacted in 2011 by power purchases required for system reliability.

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Comparisons of kWh sales and operating revenues are shown below (in thousands):



							Increase (Decrease)
Years Ended December 31:	2012			2011			Amount			Percent
kWh sales:
Retail:
Residential	2,648,348			2,633,390			14,958			0.6	%
Commercial and industrial, small	2,366,541			2,352,218			14,323			0.6
Commercial and industrial, large	1,082,973			1,096,040			(13,067		)	(1.2	)
Sales to public authorities	1,617,606			1,579,565			38,041			2.4
Total retail sales	7,715,468			7,661,213			54,255			0.7
Wholesale:
Sales for resale	64,266			62,656			1,610			2.6
Off-system sales	2,614,132			2,687,631			(73,499		)	(2.7	)
Total wholesale sales	2,678,398			2,750,287			(71,889		)	(2.6	)
Total kWh sales	10,393,866			10,411,500			(17,634		)	(0.2	)
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	234,095		$	234,086		$	9		N/A
Commercial and industrial, small	188,014			196,093			(8,079		)	(4.1	)%
Commercial and industrial, large	42,041			45,407			(3,366		)	(7.4	)
Sales to public authorities	96,132			94,370			1,762			1.9
Total retail non-fuel base revenues	560,282			569,956			(9,674		)	(1.7	)
Wholesale:
Sales for resale	2,318			2,122			196			9.2
Total non-fuel base revenues	562,600			572,078			(9,478		)	(1.7	)
Fuel revenues:
Recovered from customers during the period	130,193			145,130			(14,937		)	(10.3	)	(1)
Under (over) collection of fuel	(18,539		)	13,917			(32,456		)	N/A
New Mexico fuel in base rates	74,154			73,454			700			1.0
Total fuel revenues	185,808			232,501			(46,693		)	(20.1	)	(2)
Off-system sales:
Fuel cost	62,481			74,736			(12,255		)	(16.4	)
Shared margins	9,191			3,883			5,308			N/A
Retained margins	1,098			(560		)	1,658			N/A
Total off-system sales	72,770			78,059			(5,289		)	(6.8	)

Other	31,703			35,375			(3,672		)	(10.4	)	(3)
Total operating revenues	$	852,881		$	918,013		$	(65,132	)	(7.1	)
Average number of retail customers:
Residential	340,962			336,219			4,743			1.4
Commercial and industrial, small	37,966			37,652			314			0.8
Commercial and industrial, large	50			50			—			N/A
Sales to public authorities	4,610			4,626			(16		)	(0.3	)
Total	383,588			378,547			5,041			1.3

___________________________


(1)	Excludes $6.9 million and $12.0 million of refunds in 2012 and 2011, respectively, related to prior periods' Texas deferred fuel revenues.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $14.8 million in 2012 and 2011, respectively.


(3)	Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company.

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							Increase (Decrease)
Years Ended December 31:	2011			2010			Amount			Percent
kWh sales:
Retail:
Residential	2,633,390			2,508,834			124,556			5.0	%
Commercial and industrial, small	2,352,218			2,295,537			56,681			2.5
Commercial and industrial, large	1,096,040			1,087,413			8,627			0.8
Sales to public authorities	1,579,565			1,542,389			37,176			2.4
Total retail sales	7,661,213			7,434,173			227,040			3.1
Wholesale:
Sales for resale	62,656			53,637			9,019			16.8
Off-system sales	2,687,631			2,822,732			(135,101		)	(4.8	)
Total wholesale sales	2,750,287			2,876,369			(126,082		)	(4.4	)
Total kWh sales	10,411,500			10,310,542			100,958			1.0
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	234,086		$	217,615		$	16,471		7.6	%
Commercial and industrial, small	196,093			188,390			7,703			4.1
Commercial and industrial, large	45,407			43,844			1,563			3.6
Sales to public authorities	94,370			86,460			7,910			9.1
Total retail non-fuel base revenues	569,956			536,309			33,647			6.3
Wholesale:
Sales for resale	2,122			1,943			179			9.2
Total non-fuel base revenues	572,078			538,252			33,826			6.3
Fuel revenues:
Recovered from customers during the period	145,130			170,588			(25,458		)	(14.9	)	(1)
Under (over) collection of fuel	13,917			(35,408		)	49,325			N/A
New Mexico fuel in base rates	73,454			71,876			1,578			2.2
Total fuel revenues	232,501			207,056			25,445			12.3		(2)
Off-system sales:
Fuel cost	74,736			93,516			(18,780		)	(20.1	)
Shared margins	3,883			6,114			(2,231		)	(36.5	)
Retained margins	(560		)	5,687			(6,247		)	N/A
Total off-system sales	78,059			105,317			(27,258		)	(25.9	)

Other	35,375			26,626			8,749			32.9		(3)
Total operating revenues	$	918,013		$	877,251		$	40,762		4.6
Average number of retail customers:
Residential	336,219			331,869			4,350			1.3
Commercial and industrial, small	37,652			36,536			1,116			3.1
Commercial and industrial, large	50			49			1			2.0
Sales to public authorities	4,626			4,701			(75		)	(1.6	)
Total	378,547			373,155			5,392			1.4

_______________________


(1)	Excludes $12.0 million and $34.8 million of refunds in 2011 and 2010, respectively, related to prior periods' Texas deferred fuel revenues.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $14.8 million and $16.1 million in 2011 and 2010, respectively.


(3)	Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company.

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Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 36% of our available net generating capacity and approximately 54% of our Company-generated energy for the twelve months ended December 31, 2012. 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 decreased $47.3 million or 15.9% for the twelve months ended December 31, 2012 compared to 2011, primarily due to (i) a decrease of $36.4 million in natural gas costs due to a 28% decrease in the average costs of gas partially offset by a 6% increase in MWh generated with natural gas, and (ii) decreased costs of purchased power of $14.9 million resulting from a 17% decrease in MWh purchased and a 3% decrease in the average price of power purchased. This decrease was partially offset by an increase of $5.7 million in the cost of nuclear fuel due to an 11% increase in the cost of nuclear fuel consumed and a 2% increase in MWh generated with nuclear fuel.

Average costs per MWh were essentially flat while energy expenses increased $6.9 million or 2.4% for the twelve months ended December 31, 2011 as compared to twelve months ended December 31, 2010 due to increased energy requirements. Energy expenses in 2011, compared to 2010, increased primarily due to: (i) an increase of $10.7 million in natural gas costs due to a 16% increase in MWh generated with natural gas partially offset by a 6% decrease in the average price of natural gas; (ii) an increase of $8.7 million in the cost of nuclear fuel primarily due to a 14% increase in the cost of nuclear fuel consumed and a $3.3 million DOE settlement related to spent nuclear fuel received in 2010 with no comparable activity in 2011; and (iii) an increase of $4.3 million in coal expense due to a $2.3 million adjustment for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361, a favorable adjustment related to a contract renegotiation of $0.5 million in 2010, and a 12% increase in the cost of coal burned. These increases were partially offset by a $16.8 million decrease in purchased power cost due to a 12% decrease in MWhs purchased and a 7% decrease in the average price of purchased power.

The table below details the sources and costs of energy for 2012, 2011 and 2010.



	2012						2011
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	127,833		3,560,763	$	35.90	$	164,260	(a)	3,346,789	$	50.02
Coal	13,604			655,108	20.77		15,273		(b)	647,932	19.97
Nuclear	49,639			5,045,772	9.84		43,974			4,942,055	8.90
Total	191,076			9,261,643	20.63		223,507			8,936,776	25.10
Purchased power	60,251			1,768,810	34.06		75,149			2,135,124	35.20
Total energy	$	251,327		11,030,453	22.78		$	298,656		11,071,900	27.05


	2010
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	153,568		2,890,110	$	53.14
Coal	11,011			650,236	17.79
Nuclear	35,250		(c)	4,925,313	7.82
Total	199,829			8,465,659	24.06
Purchased power	91,916			2,420,869	37.97
Total energy	$	291,745		10,886,528	27.15

_____________________


(a)	Natural gas costs exclude $3.2 million of energy expenses capitalized related to Newman Unit 5 pre-commercial testing recorded in 2011.


(b)	Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011.


(c)	Includes a DOE refund of $3.3 million recorded in 2010.

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Other operations expense

Other operations expense increased $7.0 million or 3.0% in 2012 compared to 2011 primarily due to: (i) increased pension and benefits expense of $5.5 million reflecting changes in actuarial assumptions used to calculate expenses for our pension plans; (ii) increased power production operation expense at both Palo Verde and our fossil-fuel generating plants; and (iii) increased distribution operations expense. These increases were partially offset by decreased customer care expenses related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts.

Other operations expense increased $5.3 million or 2.4% in 2011 compared to 2010 primarily due to: (i) increased customer care expenses of $3.3 million related to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs; and (ii) increased transmission operations expense of $2.5 million primarily due to increased wheeling expense and a reliability study for the North American Electric Reliability Corporation.

Maintenance expense

Maintenance expenses decreased $1.8 million or 2.8% in 2012 compared to 2011 due primarily to decreased maintenance expense at Palo Verde of $3.2 million as a result of decreased maintenance during refueling outages in 2012 compared to refueling outages in 2011 partially offset by increased maintenance expense at our fossil-fuel generating plants.

Maintenance expenses increased $5.3 million or 9.3% in 2011 compared to 2010 due to an increase in maintenance expense largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades at our fossil-fuel generating plants.

Depreciation and amortization expense

Depreciation and amortization expense decreased $2.8 million or 3.4% in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in 2012. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant.

Depreciation and amortization expense increased $0.3 million or 0.4% in 2011 compared to 2010 primarily due to increases in depreciable plant balances including Phase II of Newman Unit 5 and increased depreciation rates, largely offset by a reduction in depreciation rates related to Palo Verde resulting from the approval of the license extension for Palo Verde by the NRC in April 2011.

Taxes other than income taxes

Taxes other than income taxes increased $1.9 million or 3.4% in 2012 compared to 2011 primarily due to increased revenue-related taxes and increased property taxes in New Mexico. Taxes other than income taxes increased $1.1 million or 2.0% in 2011 compared to 2010 primarily due to increased revenue-related taxes and increased property taxes in Texas.

Other income (deductions)

Other income (deductions) increased $2.6 million or 22.4% in 2012 compared to 2011 primarily as a result of: (i) increased allowance for equity funds used during construction (“AEFUDC”) of $1.3 million due to higher balances of construction work in progress in 2012, and (ii) a $1.1 million gain recognized on the sale of assets with no comparable amount in 2011.

Other income (deductions) decreased $2.8 million or 19.4% in 2011 compared to 2010 due to decreased AEFUDC due to lower balances of construction work in progress in 2011. Also during 2011, we incurred net unrealized and realized losses on equity investments in our decommissioning trust of $1.4 million compared to $0.1 million in 2010. The losses on equity investments were offset by increased interest income.

Interest charges (credits)

Interest charges (credits) decreased $0.1 million or 0.3% in 2012 compared to 2011 primarily due to increased allowance for borrowed funds used during construction (“ABFUDC”) as a result of higher balances of construction work in progress in 2012 partially offset by interest expense on the $150 million in aggregate principal amount of 3.30% Senior Notes issued in December 2012.

Interest charges (credits) increased $3.2 million or 7.5% in 2011 compared to 2010 primarily due to: (i) decreased ABFUDC as a result of lower balances of construction work in progress in 2011; and (ii) increased commitment fees on our revolving credit facility.

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Income tax expense

Income tax expense, before extraordinary item, decreased by $6.7 million or 12.5% in 2012 compared to 2011 primarily due to a decrease in pre-tax income. Income tax expense, before extraordinary item, increased by $2.7 million or 5.3% in 2011 compared to 2010 primarily due to increased pre-tax income partially offset by the recognition of a one-time non-cash charge to tax expense related to the impact of the tax deduction for the Medicare Part D subsidies from the Patient Protection and Affordable Care Act (“PPACA”) in March 2010 with no comparable amount in 2011. In the first quarter of 2010 the Company was required to recognize the impacts of the tax law change at the time of enactment and recorded a one-time non-cash charge to income tax expense of approximately $4.8 million. A provision of the PPACA is that, beginning in 2013, the income tax deductions for the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D subsidies received.

Extraordinary Item

As a regulated electric utility, we prepare our financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires us to show certain items as assets or liabilities on our balance sheet when the regulator provides assurance that these items will be charged to and collected from our customers or refunded to our customers. In the final order for PUCT Docket No. 37690, we were allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in our calculation of the weighted cost of debt to be recovered from our customers. We recorded the impacts of the re-application of FASB guidance for regulated operations to our Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, we recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, in our 2010 statements of operations. This item was recorded as a regulatory asset during the quarter ended September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of our 6% Senior Notes due in 2035.

New accounting standards

In February 2013, the FASB issued new guidance (ASU 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts.

Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement about presenting information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income will present, in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote dislcosures. Currently, this information is presented in different places thoughout the financial statements. We will be required to present the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) on net income with cross-references to other disclosures because FASB guidance does not require that all of our components be reclassified from accumulated other comprehensive income (loss) to net income in their entirety in the same reporting period.

ASU 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012 and early adoption is permitted. We will implement ASU 2013-02 in the first quarter of 2013.

Inflation

For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations and financial condition.

Liquidity and Capital Resources

In December 2012, we issued $150 million of 3.30% Senior Notes due to mature on December 15, 2022 to fund construction expenditures and to repay the outstanding balance of our revolving credit facility used for working capital and general corporate purposes. We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2012, our capital structure, including common stock, long-term debt, and short-term borrowings under the revolving credit facility, consisted of 44.7% common stock equity and 55.3% debt. At December 31, 2012, we had on hand $111.1 million in cash and cash equivalents.

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

Capital Requirements. During the twelve months ended December 31, 2012, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, purchases of nuclear fuel, and the payment of common stock dividends. Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. We are constructing Rio Grande Unit 9, an aeroderivative gas turbine unit with a net dependable generating capacity of 87 MW that should reach commercial operation in May 2013, at an estimated cost of approximately $92.7 million, including AFUDC. As of December 31, 2012, we had expended $81.4 million on Rio Grande Unit 9, including AFUDC, of which $44.2 million was incurred during 2012. Estimated construction expenditures for all capital projects for 2013 are approximately $264 million, and we expect our current cash balances, cash from operations, and short-term borrowings from our revolving credit facility to continue to be the primary source of funds for these capital expenditures. See Part I, Item 1, “Business - Construction Program”. Cash capital expenditures for new electric plant were $202.4 million in the twelve months ended December 31, 2012 and $178.0 million in the twelve months ended December 31, 2011.

On December 28, 2012, we paid $10.0 million of quarterly dividends to shareholders. We paid a total of $38.9 million in cash dividends during the twelve months ended December 31, 2012. On January 17, 2013, our Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013 which will require cash of $10.0 million. We expect to continue paying quarterly dividends during 2013 and we expect to review the dividend policy in the second quarter of 2013. At the current payout rate, we would expect to pay total cash dividends of approximately $40.1 million during 2013. In addition, while we do not currently anticipate repurchasing shares in 2013, we may repurchase common stock in the future. During 2011 and 2010, the Company repurchased a total of 4.3 million shares at an aggregate cost of $120.2 million, including commissions. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the twelve months ended December 31, 2012. As of December 31, 2012, 393,816 shares remain eligible for repurchase.

We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. With the initiation of a dividend in early 2011, we are moving toward primarily utilizing the distribution of dividends to maintain a balanced capital structure, supplemented by share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.

Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to accelerated tax deductions and net operating loss carryforwards, income tax payments are expected to be minimal in 2013.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $19.9 million and $13.8 million to our retirement plans during the twelve months ended December 31, 2012 and 2011, respectively. We also contributed $3.7 million and $2.2 million to our other postretirement benefit plan during the twelve months ended December 31, 2012 and 2011, respectively. We contributed $4.5 million and $8.3 million to our decommissioning trust funds for 2012 and 2011, respectively. We are in compliance with the funding requirements of the federal government for our benefit plans and decommissioning trust. We will continue to review our funding for these plans in order to meet our future obligations.

Capital Resources. Cash from operations has been our primary source for funding capital requirements. Cash from operations was $273.1 million in 2012 and $251.5 million in 2011. In 2012, cash from operations was impacted by a rate reduction in Texas. On April 17, 2012, the Council approved the settlement of our 2012 Texas retail rate case in PUCT Docket No. 40094. For Texas service areas outside the city limits of El Paso, the settlement was filed with the PUCT, and the PUCT approved the settlement on May 18, 2012. In the settlement, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas commercial and industrial customer classes. The rate decrease was effective May 1, 2012, and our non-fuel base revenues were reduced by approximately $11.7 million in 2012 as a result of these lower rates. As part of the settlement we agreed to withdraw our request to reconcile fuel costs for the period from July 1, 2009, through September 30, 2011.

On December 6, 2012, we issued $150 million in aggregate principal amount of 3.30% senior notes due December 15, 2022. The gross proceeds from the issuance of the senior notes were $149.7 million, net of a $0.3 million discount before commissions and expenses and the effective interest rate was 3.43%. On August 28, 2012, we completed a refunding transaction related to our

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4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds totaling $59.2 million in which new pollution control bonds totaling $59.2 million were issued at a fixed rate of 4.50%. The bonds are unsecured and will mature in 2042. On August 28, 2012, we also completed a remarketing transaction related to our 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds totaling $33.3 million in which new pollution control bonds totaling $33.3 million were issued at a fixed rate of 1.875%. These bonds were unsecured and mature in 2032 although they are subject to mandatory tender for purchase in 2017.

We maintain a revolving credit facility (“RCF”) for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT. RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in the Company's financial statements. The RCF has a term ending in September 2016. On March 29, 2012, the Company increased the aggregate unsecured borrowing available under the RCF from $200 million to $300 million. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT was $132.2 million at December 31, 2012, of which $22.2 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Borrowings by RGRT for nuclear fuel were $123.4 million at December 31, 2011, of which $13.4 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. No borrowings were outstanding at December 31, 2012, under the RCF for working capital and general corporate purposes.

Cash from operations has also been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. Effective July 1, 2010, we can seek to revise our fixed fuel factor at least four months after our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas. On May 1, 2012, we implemented a reduced fixed fuel factor charged to our Texas retail customers. The reduced fixed fuel factor is based upon a formula that reflects current changes in prices for natural gas.

During the twelve months ended December 31, 2012, we had increased cash from operations when compared to the same period in 2011, which reflects an increase in the collection of deferred fuel revenues in 2012. During the twelve months ended December 31, 2012, the Company had an over-recovery, net of refunds, of $11.7 million as compared to an under-recovery of fuel costs, net of refunds, of $26.0 million during the twelve months ended December 31, 2011. At December 31, 2012, we had a net fuel over-recovery balance of $4.6 million, including $2.3 million in Texas and $2.3 million in New Mexico.

We believe we have adequate liquidity through our current cash balances, cash from operations and our revolving credit facility to meet all of our anticipated cash requirements for the next twelve months. In addition, we should continue to have access to the capital markets on favorable terms.

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Contractual Obligations. Our contractual obligations as of December 31, 2012 are as follows (in thousands):



	Payments due by period
	Total		2013		2014 and 2015		2016 and 2017		2018 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,632,625	$	40,200	$	80,400	$	80,400	$	1,431,625
Pollution control bonds (2)	476,587		10,583		21,167		54,259		390,578
RGRT Senior notes (3)	140,971		5,054		25,107		59,006		51,804
Financing Obligations (including interest):
Revolving credit facility (4)	22,478		22,478		—		—		—
Purchase Obligations:
Power contracts	2,688		1,536		1,152		—		—
Fuel contracts:
Coal (5)	39,755		10,558		22,512		6,685		—
Gas (5)	327,352		37,130		71,467		76,565		142,190
Nuclear fuel (6)	117,744		16,773		34,695		31,430		34,846
Retirement Plans and Other Postretirement benefits (7)	25,829		25,829		—		—		—
Decommissioning trust funds (8)	157,172		4,535		9,071		9,071		134,495
Operating leases (9)	10,921		1,054		1,581		923		7,363
Total	$	2,954,122	$	175,730	$	267,152	$	318,339	$	2,192,901

_____________________


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


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

(3)

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


(4)	This reflects obligations outstanding under the $300 million RCF. At December 31, 2012, $22.2 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2012 and assumes this amount will be outstanding for the entire year of 2013.


(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2012. Gas obligation includes a gas storage contract and a gas transportation contract.


(6)	Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2012.

(7)

This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2013. We have no minimum cash contractual funding requirement related to our retirement income plan for 2013. However, we may decide to fund at higher levels and expect to contribute $21.8 million and $4.0 million to our retirement plans and postretirement benefit plan, respectively, in 2013, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note M, Employee Benefits. Minimum funding requirements for 2014 and beyond are not included due to the uncertainty of interest rates and the related return on assets.


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


(9)	We lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, we lease certain warehouse facilities in El Paso under a lease which expires in December 2014. We also have several other leases for office, parking facilities and equipment which expire within the next five years.

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Off-Balance Sheet Arrangements

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

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Item 7A.	Quantitative and Qualitative Disclosures About Market Risk

The following discussion regarding our market-risk sensitive instruments contains forward-looking information involving risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future. Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties involved.

We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions we hold are for purposes other than trading and are described below.

Interest Rate Risk

Our long-term debt obligations are all fixed-rate obligations, except for our revolving credit facility which is based on floating rates.

To the extent the revolving credit facility is utilized for nuclear fuel purchases, interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the PUCT and NMPRC rules which establish energy cost recovery clauses. Under these rules, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $90.6 million and $89.3 million as of December 31, 2012 and 2011, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.7 million and $0.8 million based on their fair values at December 31, 2012 and 2011, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $92.0 million and $74.9 million at December 31, 2012 and 2011, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $18.4 million and $15.0 million based on their fair values at December 31, 2012 and 2011, respectively. Declines in market prices could require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements. We will not have a requirement to expend monies held in trust before 2044 or a later period when we begin to decommission Palo Verde.

Commodity Price Risk

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

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2013, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, “Business – Energy Sources – Purchased Power” and “Regulation – Power Sales Contracts.” These agreements are generally fixed-priced contracts which qualify for the “normal purchases and normal sales” exception provided in FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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Management Report on Internal Control Over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;


•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and


•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

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

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2012. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2012, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 42 of this report.

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Item 8.Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	42

Consolidated Balance Sheets as of December 31, 2012 and 2011	43

Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010	45

Consolidated Statements of Comprehensive Operations for the years ended December 31, 2012, 2011 and 2010	46

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2012, 2011 and 2010	47

Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	48

Notes to Consolidated Financial Statements	49

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2012. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

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

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company and subsidiary as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Houston, Texas

February 25, 2013

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS



ASSETS (In thousands)	December 31,
	2012			2011
Utility plant:
Electric plant in service	$	2,857,913		$	2,789,773
Less accumulated depreciation and amortization	(1,162,483		)	(1,121,653		)
Net plant in service	1,695,430			1,668,120
Construction work in progress	287,358			167,394

Nuclear fuel; includes fuel in process of $56,129 and $49,545, respectively	189,921			171,433
Less accumulated amortization	(70,366		)	(59,882		)
Net nuclear fuel	119,555			111,551
Net utility plant	2,102,343			1,947,065
Current assets:
Cash and cash equivalents	111,057			8,208
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,906 and $3,015, respectively	62,900			76,348
Accumulated deferred income taxes	20,292			13,752
Inventories, at cost	42,358			40,222
Undercollection of fuel revenues	—			9,130
Prepayments and other	9,627			7,079
Total current assets	246,234			154,739
Deferred charges and other assets:
Decommissioning trust funds	187,053			167,963
Regulatory assets	101,590			101,027
Other	31,830			26,057
Total deferred charges and other assets	320,473			295,047
Total assets	$	2,669,050		$	2,396,851

See accompanying notes to consolidated financial statements.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)



CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2012			2011
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,520,551 and 65,295,888 shares issued, and 84,446 and 156,185 restricted shares, respectively	$	65,605		$	65,452
Capital in excess of stated value	310,994			309,777
Retained earnings	939,131			887,174
Accumulated other comprehensive loss, net of tax	(66,084		)	(77,505		)
	1,249,646			1,184,898
Treasury stock, 25,492,919 at cost	(424,647		)	(424,647		)
Common stock equity	824,999			760,251
Long-term debt	999,535			816,497
Total capitalization	1,824,534			1,576,748
Current liabilities:
Current maturities of long-term debt	—			33,300
Short-term borrowings under the revolving credit facility	22,155			33,379
Accounts payable, principally trade	61,581			51,704
Taxes accrued	29,248			30,700
Interest accrued	12,127			12,123
Overcollection of fuel revenues	4,643			2,105
Other	21,995			21,921
Total current liabilities	151,749			185,232
Deferred credits and other liabilities:
Accumulated deferred income taxes	358,674			299,475
Accrued pension liability	125,690			129,627
Accrued postretirement benefit liability	99,170			100,455
Asset retirement obligation	62,784			56,140
Regulatory liabilities	22,179			21,049
Other	24,270			28,125
Total deferred credits and other liabilities	692,767			634,871
Commitments and contingencies
Total capitalization and liabilities	$	2,669,050		$	2,396,851

See accompanying notes to consolidated financial statements.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except for share data)



	Years Ended December 31,
	2012			2011			2010
Operating revenues	$	852,881		$	918,013		$	877,251
Energy expenses:
Fuel	191,076			223,507			199,829
Purchased and interchanged power	60,251			75,149			91,916
	251,327			298,656			291,745
Operating revenues net of energy expenses	601,554			619,357			585,506
Other operating expenses:
Other operations	236,558			229,570			224,221
Maintenance	60,339			62,092			56,823
Depreciation and amortization	78,556			81,331			81,011
Taxes other than income taxes	57,443			55,561			54,489
	432,896			428,554			416,544
Operating income	168,658			190,803			168,962
Other income (deductions):
Allowance for equity funds used during construction	9,427			8,161			10,816
Investment and interest income, net	5,275			5,664			5,315
Miscellaneous non-operating income	1,415			885			1,368
Miscellaneous non-operating deductions	(2,013		)	(3,187		)	(3,206		)
	14,104			11,523			14,293
Interest charges (credits):
Interest on long-term debt and revolving credit facility	54,632			54,115			50,826
Other interest	1,190			989			254
Capitalized interest	(5,312		)	(5,177		)	(2,487		)
Allowance for borrowed funds used during construction	(5,573		)	(4,848		)	(6,671		)
	44,937			45,079			41,922
Income before income taxes and extraordinary item	137,825			157,247			141,333
Income tax expense	46,979			53,708			51,016
Income before extraordinary item	90,846			103,539			90,317
Extraordinary gain related to Texas regulatory assets, net of tax	—			—			10,286
Net income	$	90,846		$	103,539		$	100,603
Basic earnings per share:
Income before extraordinary item	$	2.27		$	2.49		$	2.08
Extraordinary gain related to Texas regulatory assets, net of tax	—			—			0.24
Net income	$	2.27		$	2.49		$	2.32
Diluted earnings per share:
Income before extraordinary item	$	2.26		$	2.48		$	2.07
Extraordinary gain related to Texas regulatory assets, net of tax	—			—			0.24
Net income	$	2.26		$	2.48		$	2.31
Dividends declared per share of common stock	$	0.97		$	0.66		$	—
Weighted average number of shares outstanding	39,974,022			41,349,883			43,129,735
Weighted average number of shares and dilutive potential shares outstanding	40,055,581			41,587,059			43,294,419

See accompanying notes to consolidated financial statements.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)



	Years Ended December 31,
	2012			2011			2010
Net income	$	90,846		$	103,539		$	100,603
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net loss arising during period	(2,109		)	(77,678		)	(9,874		)
Prior service benefit	—			—			26,605
Reclassification adjustments included in net income for amortization of:
Prior service cost	(5,762		)	(5,812		)	(2,754		)
Net loss	11,971			6,505			3,374
Net unrealized gains on marketable securities:
Net holding gains arising during period	9,927			1,570			6,665
Reclassification adjustments for net losses included in net income	1,042			1,358			122
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	385			361			338
Total other comprehensive income (loss) before income taxes	15,454			(73,696		)	24,476
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	(1,464		)	30,134			(6,287		)
Net unrealized gains on marketable securities	(2,438		)	(563		)	(1,357		)
Losses on cash flow hedges	(131		)	(203		)	(122		)
Total income tax benefit (expense)	(4,033		)	29,368			(7,766		)
Other comprehensive income (loss), net of tax	11,421			(44,328		)	16,710
Comprehensive income	$	102,267		$	59,211		$	117,313

See accompanying notes to consolidated financial statements.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(In thousands except for share data)



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

	Shares		Amount												Shares	Amount
Balances at December 31, 2009	65,094,156		$	65,094		$	301,180		$	710,255		$	(49,887	)	21,169,284	$	(303,913	)	$	722,729
Restricted common stock grants and deferred compensation	112,891		113			2,302													2,415
Performance share awards vested	9,525		10			653													663
Stock awards withheld for taxes	(10,261	)	(11		)	(236		)											(247		)
Forfeitures and lapsed restricted common stock	(37,993	)	(38		)	(463		)											(501		)
Deferred taxes on stock incentive plan						350													350
Stock options exercised	96,742		97			1,282													1,379
Net income									100,603										100,603
Other comprehensive income												16,710							16,710
Treasury stock acquired, at cost															1,524,711	(33,726		)	(33,726		)
Balances at December 31, 2010	65,265,060		65,265			305,068			810,858			(33,177		)	22,693,995	(337,639		)	810,375
Restricted common stock grants and deferred compensation	118,110		118			3,087													3,205
Performance share awards vested	40,895		41			587													628
Stock awards withheld for taxes	(23,702	)	(24		)	(715		)											(739		)
Forfeitures and lapsed restricted common stock	(2,200	)	(2		)														(2		)
Deferred taxes on stock incentive plan						1,112													1,112
Stock options exercised	53,910		54			638													692
Net income									103,539										103,539
Other comprehensive loss												(44,328		)					(44,328		)
Dividends declared									(27,223		)								(27,223		)
Treasury stock acquired, at cost															2,798,924	(87,008		)	(87,008		)
Balances at December 31, 2011	65,452,073		65,452			309,777			887,174			(77,505		)	25,492,919	(424,647		)	760,251
Restricted common stock grants and deferred compensation	87,428		87			1,691													1,778
Performance share awards vested	174,038		174			1,019													1,193
Stock awards withheld for taxes	(52,778	)	(52		)	(1,770		)											(1,822		)
Forfeitures and lapsed restricted common stock	(88,100	)	(88		)	(1,206		)											(1,294		)
Deferred taxes on stock incentive plan						1,101													1,101
Stock options exercised	32,336		32			382													414
Net income									90,846										90,846
Other comprehensive income												11,421							11,421
Dividends declared									(38,889		)								(38,889		)
Balances at December 31, 2012	65,604,997		$	65,605		$	310,994		$	939,131		$	(66,084	)	25,492,919	$	(424,647	)	$	824,999

See accompanying notes to consolidated financial statements.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2012			2011			2010
Cash Flows From Operating Activities:
Net income	$	90,846		$	103,539		$	100,603
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	78,556			81,331			81,011
Amortization of nuclear fuel	42,953			37,018			31,316
Extraordinary gain related to Texas regulatory assets, net of tax	—			—			(10,286		)
Deferred income taxes, net	43,561			45,688			27,456
Allowance for equity funds used during construction	(9,427		)	(8,161		)	(10,816		)
Other amortization and accretion	14,724			19,875			16,740
Other operating activities	(479		)	1,036			(881		)
Change in:
Accounts receivable	13,448			(4,663		)	(1,303		)
Inventories	(1,926		)	(3,750		)	1,143
Net overcollection (undercollection) of fuel revenues	11,668			(26,001		)	958
Prepayments and other	(2,784		)	(2,538		)	(544		)
Accounts payable	1,725			4,401			(9,634		)
Taxes accrued	(3,054		)	11,915			18,523
Other current liabilities	78			(2,262		)	1,127
Deferred charges and credits	(6,781		)	(5,911		)	(6,063		)
Net cash provided by operating activities	273,108			251,517			239,350
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(202,387		)	(178,041		)	(169,966		)
Cash additions to nuclear fuel	(46,009		)	(39,551		)	(34,277		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(15,000		)	(13,009		)	(17,487		)
Nuclear fuel	(5,312		)	(5,177		)	(2,487		)
Allowance for equity funds used during construction	9,427			8,161			10,816
Decommissioning trust funds:
Purchases, including funding of $4.5 million, $8.3 million and $8.2 million, respectively	(107,705		)	(95,441		)	(73,192		)
Sales and maturities	98,542			82,926			61,656
Proceeds from sale of investments in debt securities	—			2,000			—
Other investing activities	2,390			727			286
Net cash used for investing activities	(266,054		)	(237,405		)	(224,651		)
Cash Flows From Financing Activities:
Repurchases of common stock	—			(86,508		)	(33,726		)
Dividends paid	(38,889		)	(27,223		)	—
Pollution control bonds:
Proceeds	92,535			—			—
Payments	(92,535		)	—			—
Proceeds from issuance of senior notes	149,682			—			110,000
Borrowings under the revolving credit facility:
Proceeds	234,575			120,450			37,628
Payments	(245,799		)	(91,775		)	(139,922		)
Other financing activities	(3,774		)	(32		)	(1,285		)
Net cash provided by (used for) financing activities	95,795			(85,088		)	(27,305		)
Net increase (decrease) in cash and cash equivalents	102,849			(70,976		)	(12,606		)
Cash and cash equivalents at beginning of period	8,208			79,184			91,790
Cash and cash equivalents at end of period	$	111,057		$	8,208		$	79,184

See accompanying notes to consolidated financial statements.

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INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



	Page
Note A. Summary of Significant Accounting Policies	50

Note B. New Accounting Standards	53

Note C. Regulation	53

Note D. Regulatory Assets and Liabilities	56

Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	57

Note F. Accounting for Asset Retirement Obligations	59

Note G. Common Stock	60

Note H. Accumulated Other Comprehensive Loss	66

Note I. Long-Term Debt and Financing Obligations	66

Note J. Income Taxes	68

Note K. Commitments, Contingencies and Uncertainties	71

Note L. Litigation	74

Note M. Employee Benefits	75

Note N. Franchises and Significant Customers	85

Note O. Financial Instruments and Investments	86

Note P. Supplemental Statements of Cash Flow Disclosures	90

Note Q. Selected Quarterly Financial Data (Unaudited)	91

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

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

Principles of Consolidation. The consolidated financial statements include the accounts of El Paso Electric Company and its wholly-owned subsidiary, MiraSol Energy Services, Inc. (“MiraSol”) (collectively, the “Company”). MiraSol, which began operations as a separate subsidiary in March 2001, provided energy efficiency products and discontinued these activities in 2002. All intercompany transactions and balances have been eliminated in consolidation.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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

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

Extraordinary item. As discussed in the previous paragraph, FASB guidance for regulated operations requires the Company to show certain items as assets or liabilities on its balance sheet when the regulator provides assurance that these items will be charged to and collected from customers or refunded to customers. In the final order for the Public Utility Commission of Texas ("PUCT") Docket No. 37690, the Company was allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in its calculation of the weighted cost of debt to be recovered from its customers. The Company recorded the impacts of the re-application of FASB guidance for regulated operations to its Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, the Company recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, pursuant to the final order received from the PUCT, in its statements of operations for the quarter ended September 30, 2010. The regulatory asset will be amortized over the remaining life of the Company's 6% Senior Notes due in 2035.

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

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2012, 2011 and 2010 was 2.64%, 2.80%, and 3.21%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note E.

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

AFUDC and Capitalized Interest. The Company capitalizes interest (ABFUDC) and common equity (AEFUDC) costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a monthly basis. The AFUDC rates used in 2012 and 2011 were 8.53% and 8.54%, respectively. The AFUDC rate utilized for the first six months of 2010 was 9.01% and 8.47% thereafter.

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

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

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

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

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

Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the PUCT. The Company’s New Mexico retail customers and its sales for resale customer are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission (“NMPRC”) and the FERC. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/undercollection of fuel revenues in the consolidated balance sheets. See Note C.

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $17.9 million and $19.6 million at December 31, 2012 and 2011, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2012, 2011 and 2010 are as follows (in thousands):



	2012		2011		2010
Balance at beginning of year	$	3,015	$	2,885	$	1,191
Additions:
Charged to costs and expense	3,087		6,209		4,756
Recovery of previous write-offs	2,041		2,034		852
Uncollectible receivables written off	5,237		8,113		3,914
Balance at end of year	$	2,906	$	3,015	$	2,885

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

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

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

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

Reclassification. Certain amounts in the consolidated financial statements for 2011 and 2010 have been reclassified to conform with the 2012 presentation.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

B. New Accounting Standards

Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement about presenting information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income will present, in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote dislcosures. Currently, this information is presented in different places thoughout the financial statements. The Company will be required to present the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) on net income with cross-references to other disclosures because FASB guidance does not require that all of the Company's components be reclassified from accumulated other comprehensive income (loss) to net income in their entirety in the same reporting period.

ASU 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012 and early adoption is permitted. The Company will implement ASU 2013-02 in the first quarter of 2013.

C. Regulation

General

Texas Regulatory Matters

Under the terms of the settlement, among other things, the Company agreed to:


•	A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;


•	Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;


•	Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and


•A	two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Docket

No.

Date Filed

Date Approved

Recovery Period

Refund Period

Refund

Amount Authorized (In Thousands)

40622

August 3, 2012

September 28, 2012

January 2011- June 2012

September 2012

6,600

The Company filed the following petition in 2012 with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:



Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor	Effective Billing Month
40302	April 12, 2012	April 25, 2012	(18.5)%	May 2012

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

New Mexico Regulatory Matters

Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement ("LTPPA") with Macho Springs Solar, LLC ("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs in the Company's New Mexico service territory. The Company also seeks approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. The hearing is scheduled to begin March 14, 2013 and a final order is expected by the end of May 2013.

Federal Regulatory Matters

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

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

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Sales for Resale

D. Regulatory Assets and Liabilities

The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company's consolidated balance sheets are presented below (in thousands):



	Amortization Period Ends	December 31, 2012		December 31, 2011
Regulatory assets
Regulatory tax assets (a)	(b)	$	57,551	$	52,281
Loss on reacquired debt (c)	May 2035	19,191		20,044
Final coal reclamation (a)	July 2016	5,473		6,655
Nuclear fuel postload daily financing charge	(d)	3,833		3,470
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	926		578
Texas energy efficiency	(e)	536		4,497
Texas 2009 rate case costs (f)	June 2012	—		1,146
Texas 2012 rate case costs (f)	April 2014	2,335		648
Texas military base discount and recovery factor	(h)	2,116		2,526
New Mexico procurement plan costs	(g)	139		139
New Mexico renewable energy credits	(g)	4,033		2,884
New Mexico 2009 rate case costs (f)	December 2012	—		253
New Mexico 2010 FPPCAC audit	(g)	433		427
New Mexico Palo Verde deferred depreciation	(b)	5,024		5,176
New Mexico energy efficiency	(e)	—		303
Total regulatory assets		$	101,590	$	101,027
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	16,666	$	16,138
Accumulated deferred investment tax credit (i)	(b)	4,587		4,911
New Mexico energy efficiency	(e)	926		—
Total regulatory liabilities		$	22,179	$	21,049

________________


(a)	No specific return on investment is required since related assets and liabilities, including accumulated deferred income taxes and reclamation liability, offset.


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


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


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


(e)	This item is recovered or credited through an annual recovery factor.


(f)	This item is included in rate base which earns a return on investment.


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

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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


(i)	This item is excluded from rate base.

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

The table below presents the balance of each major class of depreciable assets at December 31, 2012 (in thousands):



	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	795,259	$	(257,540	)	$	537,719
Steam and other	561,440		(242,992		)	318,448
Total production	1,356,699		(500,532		)	856,167
Transmission	407,184		(245,700		)	161,484
Distribution	917,931		(326,234		)	591,697
General	120,081		(59,641		)	60,440
Intangible	56,018		(30,376		)	25,642
Total	$	2,857,913	$	(1,162,483	)	$	1,695,430

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




2010	$	6,312
2011	6,668
2012	7,183
2013 (estimated)	6,003
2014 (estimated)	5,234
2015 (estimated)	3,803
2016 (estimated)	2,879
2017 (estimated)	2,214

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

Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station (“Four Corners”) and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2012 and 2011 is as follows (in thousands):



	December 31, 2012						December 31, 2011
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	795,259		$	213,155		$	768,284		$	211,983
Accumulated depreciation	(257,540		)	(168,569		)	(240,862		)	(164,622		)
Construction work in progress	64,623			2,401			53,822			1,634
Total	$	602,342		$	46,987		$	581,244		$	48,995

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Palo Verde

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

NRC. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance.

License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively. The extension of the operating leases reduced the Company's annual depreciation and amortization expense by approximately $11.0 million and reduced the Company's annual accretion expense by approximately $4.4 million. For 2011, the extension of the operating leases had the effect of reducing depreciation and amortization expense by approximately $8.2 million and reducing the accretion expense on the Palo Verde asset retirement obligation by approximately $3.1 million.

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2012, the Company’s decommissioning trust fund had a balance of $187.1 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjust its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. On March 30, 2011, the Palo Verde Participants approved the 2010 Palo Verde decommissioning study (the “2010 Study”). The 2010 Study reflects the extension of the operating license from 40 years to 60 years. The 2010 Study estimated that the Company must fund approximately $357.4 million (stated in 2010 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $33.0 million (stated in 2010 dollars) from the 2007 Palo Verde decommissioning study (the “2007 Study”). The net effect of these changes lowered the asset retirement obligation by $41.7 million and lowered annual expenses after March 2011. Although the 2010 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty.

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the “Waste Act”), 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. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde participants. The DOE failed to begin accepting Palo Verde's spent nuclear fuel, and APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.

The 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

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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. None of these lawsuits have been conclusively decided by the courts. In addition, the NRC's rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel has been challenged and is being reworked. The Company cannot predict when spent fuel shipments to the DOE will commence.

APS and the Company believe that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the current term of its operating license. The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde which the Company believes are the responsibility of the DOE. These costs are assigned to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs.

Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $12.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 million, and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $117.5 million, subject to an annual limit of $17.5 million. Based upon the Company's 15.8% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $55.7 million, with an annual payment limitation of approximately $8.3 million.

The Palo Verde Participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $9.8 million for the current policy period.

F. Accounting for Asset Retirement Obligations

The Company complies with FASB guidance for asset retirement obligations (“ARO”). This guidance affects the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and the method used to report the decommissioning obligation. The Company also complies with FASB guidance for conditional asset retirement obligations which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s AROs are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes

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any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The 2012 ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2010 Palo Verde decommissioning study. See Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company has six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2012 is $187.1 million.

FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. In April 2011, the Company implemented the 2010 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to (i) increase estimated cash flows from the 2007 Study to the 2010 Study, and (ii) change estimated probabilities due to Palo Verde license extension (see Note E). The assumptions used to calculate the original Palo Verde ARO liability and the revised Palo Verde ARO liability are as follows:



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

A roll forward of the Company's ARO liability is presented below and revisions to estimates include both the increase to estimated cash flows and the change in estimated probabilities for life extension due to the approval of a Palo Verde license extension in 2011 and the change in the estimated probability of extending the Four Corners' original lease term in 2012.



	2012			2011			2010
ARO liability at beginning of year	$	56,140		$	92,911		$	85,358
Liabilities incurred	—			—			—
Liabilities settled	(450		)	(793		)	(85		)
Revisions to estimate	1,929			(41,670		)	(377		)
Accretion expense	5,165			5,692			8,015
ARO liability at end of year	$	62,784		$	56,140		$	92,911

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

G. Common Stock

Overview

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

Long-Term Incentive Plan

On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the “2007 LTIP”) and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock

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appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.

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

The following table summarizes the transactions in the Company’s stock options for 2012:



	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value		Cash Received		Realized Current Tax Benefits
					(In thousands)		(In thousands)		(In thousands)
Options outstanding at December 31, 2011	47,336	$	12.80
Options exercised	32,336	12.81					$	414	$	210
Options outstanding at December 31, 2012	15,000	12.78		0.93	$	287
Exercisable at December 31, 2012	15,000	12.78		0.93	287

The intrinsic value of stock options exercised in 2012, 2011 and 2010 were $0.6 million, $1.0 million and $1.3 million, respectively. No options were forfeited, vested or expired during 2012, 2011 and 2010.

All stock options outstanding have vested. No compensation cost was recognized in 2010, 2011 and 2012 for stock options and there is no unrecognized compensation expense related to stock options.

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

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards in 2012, 2011 and 2010 is presented below (in thousands):



	2012		2011		2010

Expense (a)	$	1,508	$	2,258	$	1,589
Deferred tax benefit	528		790		556
Current tax benefit recognized	94		518		169

_____________________

(a) Any capitalized costs related to these expenses would be less than $0.1 million for all years.

The aggregate intrinsic value and fair value at grant date of restricted stock which vested in 2012, 2011 and 2010 is presented below (in thousands):



	2012		2011		2010

Aggregated intrinsic value	$	2,242	$	3,279	$	1,749
Fair value at grant date	1,973		1,799		1,265

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The unvested restricted stock transactions for 2012 are presented below:



	Total Shares		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Restricted shares outstanding at December 31, 2011	156,185		$	26.87
Restricted stock awards	87,428		32.45
Lapsed restrictions and vesting	(71,067	)	27.76
Forfeitures (b)	(88,100	)	27.48
Restricted shares outstanding at December 31, 2012	84,446		31.26		$	1,184	$	2,695

_______________________

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

(b) Forfeitures include 79,489 shares with a weighted average grant date fair value of $27.46 which were forfeited by the March 2, 2012 resignation of the Company's former Chief Executive Officer.

The weighted average fair value per share at grant date for restricted stock awarded during 2012, 2011 and 2010 were:



	2012		2011		2010
Weighted average fair value per share	$	32.45	$	28.98	$	20.03

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

Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plan, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies between 0% to 200% of performance share awards.

Detail of performance shares vested follows:



Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Period Compensation Costs Expensed	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
January 1, 2013	150.0	%	64,275	$	849	2010-2012	$	2,051
January 1, 2012	175.0	%	174,038	1,193		2009-2011	6,029
July 9, 2011	112.5	%	2,250	23		2008-2011	75
September 3, 2011	112.5	%	3,825	40		2008-2011	129
January 1, 2011	112.5	%	34,820	565		2008-2010	959

In 2013, 2014 and 2015, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. Excluding the 64,275 shares that vested on January 1, 2013, the actual number of shares to be issued can range from zero to 170,366 shares.

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The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the plan’s term structure and includes the volatilities of all members of the defined peer group.

The outstanding performance share awards at the 100% performance level is summarized below:



	Number Outstanding		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Performance shares outstanding at December 31, 2011	295,614		$	18.57
Performance share awards	88,133		32.74
Performance shares vested	(99,450	)	12.00
Performance shares lapsed	—		—
Performance shares forfeited (b)	(156,264	)	24.26
Performance shares outstanding at December 31, 2012	128,033		26.48		$	1,269	$	4,086

_______________________

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

(b) Forfeitures include 132,914 shares with a weighted average grant date fair value of $23.80 which were forfeited by the March 2, 2012 resignation of the Company's former Chief Executive Officer.

A summary of information related to performance shares for 2012, 2011 and 2010 is presented below:



	2012		2011		2010
Weighted average per share grant date fair value per share of performance shares awarded	$	32.74	$	23.45	$	19.82
Fair value of performance shares vested (in thousands)	1,193		628		663
Intrinsic value of performance shares vested (in thousands)	3,464		1,032		193
Compensation expense (in thousands) (a)	170		1,573		988
Deferred tax benefit related to compensation expense (in thousands)	59		551		346

_____________________

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

Repurchase Program

No shares of common stocks were repurchased during the twelve months ended December 31, 2012. Detail regarding the Company's stock repurchase program are presented below:

______________________


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

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(b)	Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs.

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

Dividend Policy

On December 28, 2012, the Company paid $10.0 million in quarterly cash dividends to shareholders. The Company paid a total of $38.9 million and $27.2 million in cash dividends during the twelve months ended December 31, 2012 and 2011. On January 17, 2013, the Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013.

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Basic and Diluted Earnings Per Share

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



	Years Ended December 31,
	2012			2011			2010
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	39,974,022			41,349,883			43,129,735
Dilutive effect of unvested performance awards	66,756			206,658			101,780
Dilutive effect of stock options	14,803			30,518			62,904
Diluted number of common shares outstanding	40,055,581			41,587,059			43,294,419
Basic net income per common share:
Net income	$	90,846		$	103,539		$	100,603
Income allocated to participating restricted stock	(256		)	(471		)	(403		)
Net income available to common shareholders	$	90,590		$	103,068		$	100,200
Diluted net income per common share:
Net income	$	90,846		$	103,539		$	100,603
Income reallocated to participating restricted stock	(256		)	(469		)	(401		)
Net income available to common shareholders	$	90,590		$	103,070		$	100,202
Basic net income per common share:
Distributed earnings	$	0.97		$	0.66		$	—
Undistributed earnings	1.30			1.83			2.32
Basic net income per common share	$	2.27		$	2.49		$	2.32
Diluted net income per common share:
Distributed earnings	$	0.97		$	0.66		$	—
Undistributed earnings	1.29			1.82			2.31
Diluted net income per common share	$	2.26		$	2.48		$	2.31

The amount of restricted stock awards, performance shares and stock options excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:



	Year Ended December 31,
	2012	2011	2010
Restricted stock awards	45,178	81,653	75,270
Performance shares (a)	57,625	—	24,225
Stock options	—	—	—

_____________________


(a)	Performance shares were excluded from the computation of diluted earnings per share as no payouts would have been required based upon performance at the end of each corresponding period. These amounts assume a 100% performance level payout.

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H. Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss consists of the following components (in thousands):



	Net Unrealized Gains (Losses) on Marketable Securities			Unrecognized Pension and Postretirement Benefit Costs			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Loss
Balance at December 31, 2009	$	5,868		$	(42,586	)	$	(13,169	)	$	(49,887	)
Other comprehensive income	6,787			17,351			338			24,476
Income tax expense	(1,357		)	(6,287		)	(122		)	(7,766		)
Balance at December 31, 2010	11,298			(31,522		)	(12,953		)	(33,177		)
Other comprehensive income (loss)	2,928			(76,985		)	361			(73,696		)
Income tax benefit (expense)	(563		)	30,134			(203		)	29,368
Balance at December 31, 2011	13,663			(78,373		)	(12,795		)	(77,505		)
Other comprehensive income	10,969			4,100			385			15,454
Income tax expense	(2,438		)	(1,464		)	(131		)	(4,033		)
Balance at December 31, 2012	$	22,194		$	(75,737	)	$	(12,541	)	$	(66,084	)

I. Long-Term Debt and Financing Obligations

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



	December 31,
	2012			2011
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	63,500		$	63,500
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	59,235			59,235
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	37,100			37,100
1.875% 2012 Series A refunding bonds, due 2032 (2.34% effective interest rate)	33,300			33,300
Total Pollution Control Bonds	193,135			193,135
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	397,934			397,894
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,783			148,768
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,683			—
Total Senior Notes	696,400			546,662
RGRT Senior Notes (3):
3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate)	15,000			15,000
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	50,000			50,000
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	45,000			45,000
Total RGRT Senior Notes	110,000			110,000
Total long-term debt	999,535			849,797
Financing Obligations:
Revolving Credit Facility ($22,155 due in 2013) (4)	22,155			33,379
Total long-term debt and financing obligations	1,021,690			883,176
Current Portion (amount due within one year):
Current maturities of long-term debt	—			(33,300		)
Short-term borrowings under the revolving credit facility	(22,155		)	(33,379		)
	$	999,535		$	816,497

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_____________________


(1)	Pollution Control Bonds (“PCBs”)

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. In August 2012, the 4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $59.2 million was refunded at a fixed rate of 4.50% and will mature on August 1, 2042. The 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million was remarketed in August 2012 at a fixed rate of 1.875%, until September 1, 2017 when the bonds are subject to mandatory tender for purchase. These bonds will mature on June 1, 2032.


(2)	Senior Notes

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

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

The 3.30% senior notes have an aggregate principal amount of $150.0 million, were issued in December 2012 and will mature on December 15, 2022. The gross proceeds, net of a $0.3 million discount, will be used to fund construction expenditures and for working capital and general corporate purposes.


(3)	RGRT Senior Notes

On August 17, 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde, entered into a Note Purchase Agreement (the “Agreement”) with various institutional purchasers. Under the terms of the Agreement, RGRT sold to the purchasers $110 million aggregate principal amount of senior notes (the "Notes"). The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of the RGRT are reported as assets and liabilities of the Company.

RGRT will pay interest on the Notes on February 15 and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The Agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2012.

The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended.

The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT to repay amounts borrowed under the revolving credit facility and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the Notes and amounts borrowed from the revolving credit facility.


(4)	Revolving Credit Facility

On March 29, 2012, the Company and RGRT entered into the Incremental Facility Assumption Agreement ("the Assumption Agreement") related to the revolving credit agreement (the “RCF”) with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. The Assumption Agreement provides for the Company's exercise in full of the accordian feature provided for under the RCF, increasing the

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aggregate unsecured borrowing available from $200 million to $300 million. The RCF has a term ending September 2016. No other material modifications were made to the terms and conditions of the RCF.

The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under the RCF is recorded as short-term borrowings on the consolidated balance sheet. The RCF is unsecured. The RCF requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2012. As of December 31, 2012, the total amount borrowed by RGRT was $22.2 million for nuclear fuel under the RCF. No borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.5% as of December 31, 2012.

As of December 31, 2012, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):




2013	$	—
2014	—
2015	15,000
2016	—
2017	83,300

The $22.2 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2013.

J. Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2012 and 2011 are presented below (in thousands):



	December 31,
	2012			2011
Deferred tax assets:
Benefit of tax loss carryforwards	$	7,798		$	21,737
Alternative minimum tax credit carryforward	21,599			19,863
Pensions and benefits	86,816			87,946
Asset retirement obligation	21,710			20,100
Deferred fuel	1,951			—
Other	14,549			20,524
Total gross deferred tax assets	154,423			170,170
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(459,079		)	(424,319		)
Decommissioning	(29,416		)	(22,633		)
Deferred fuel	—			(2,493		)
Other	(4,310		)	(6,448		)
Total gross deferred tax liabilities	(492,805		)	(455,893		)
Net accumulated deferred income taxes	$	(338,382	)	$	(285,723	)

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

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The Company recognized income tax expense for 2012, 2011 and 2010 as follows (in thousands):



	Years Ended December 31,
	2012			2011			2010
Income tax expense:
Federal:
Current	$	1,487		$	5,084		$	19,251
Deferred	43,187			46,864			31,386
Total federal income tax	44,674			51,948			50,637
State:
Current	1,931			2,936			4,308
Deferred	697			(924		)	1,947
Total state income tax	2,628			2,012			6,255
Amortization of accumulated investment tax credits	(323		)	(252		)	(107		)
Total income tax expense	46,979			53,708			56,785
Tax expense classified as extraordinary gain	—			—			(5,769		)
Total income tax expense before extraordinary item	$	46,979		$	53,708		$	51,016

Current federal income tax expense for 2010 reflects taxes accrued under the alternative minimum tax (“AMT”). Deferred federal income tax for 2010 includes an offsetting AMT benefit of $10.2 million. There was no offsetting AMT benefit for 2012 or 2011. As of December 31, 2012, the Company had $21.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2012, the Company had tax loss carryforwards of $7.7 million and $0.1 million that have lives of 20 years and 5 years, respectively.

Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands):



	Years Ended December 31,
	2012			2011			2010
Federal income tax expense computed on income at statutory rate	$	48,239		$	55,036		$	55,086
Difference due to:
State taxes, net of federal benefit	1,708			1,308			4,066
AEFUDC	(1,845		)	(2,295		)	(3,578		)
Permanent tax differences	(604		)	(303		)	(3,103		)
Patient Protection and Affordable Care Act ("PPACA")	—			—			4,787
Other	(519		)	(38		)	(473		)
Total income tax expense	46,979			53,708			56,785
Tax expense classified as extraordinary gain	—			—			(5,769		)
Total income tax expense before extraordinary item	$	46,979		$	53,708		$	51,016
Effective income tax rate	34.1		%	34.2		%	36.1		%
Effective income tax rate without PPACA	34.1		%	34.2		%	33.0		%

The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2008 and in the state jurisdictions for years prior to 1998. The Company is currently under audit in the federal jurisdiction for tax years 2009 through 2012 and in Texas for 2007. A deficiency notice relating to the Company’s 1998 through 2003 and 2006 and 2007 income tax returns in Arizona contests a pollution control credit, a research and development credit and the sales and property apportionment factors. The Company is contesting these adjustments.

On March 23, 2010, the PPACA was signed into law. A major provision of the law is that, beginning in 2013, the income tax deductions for the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D

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subsidies received. The Company was required to recognize the impacts of the tax law change at the time of enactment and recorded a one-time non-cash charge to income tax expense of approximately $4.8 million in the first quarter of 2010.

FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In January 2010, the Company filed for a change of accounting method with the IRS related to the way in which units of property are determined for purposes of determining capitalized tax assets. The change was included in the 2009 federal income tax return, with additional amounts included in the 2010 federal income tax return. In August of 2012, the Company filed a change of accounting method with the IRS, effectively adopting the safe harbor provisions of Rev. Proc 2011-43 related to units of property for capitalized tax assets. The change was included in the 2011 federal income tax return. The Company recorded an additional unrecognized tax position of $1.6 million, $2.2 million and $6.3 million, in 2012, 2011, 2010, respectively, related to the changes in accounting method in 2009 through 2012. An additional unrecognized tax position may be recognized after the IRS audits the 2009 through 2012 tax returns. The Company recorded an unrecognized tax position of $1.4 million in 2012 related to depreciation amounts deducted in prior year Texas franchise tax returns. A reconciliation of the December 31, 2012, 2011 and 2010 amount of unrecognized tax benefits is as follows (in thousands):



	2012			2011		2010
Balance at January 1	$	9,500		$	7,300	$	600
Additions for tax positions related to the current year	1,600			2,200		6,300
Reductions for tax positions related to the current year	(900		)	—		—
Additions for tax positions of prior years	1,400			—		400
Reductions for tax positions of prior years	(1,800		)	—		—
Balance at December 31	$	9,800		$	9,500	$	7,300

If recognized, $1.2 million of the unrecognized tax position at December 31, 2012, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $1.5 million for the year ended December 31, 2012.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the years ended December 31, 2012 and 2010, the Company recognized a benefit of $0.3 million and $0.1 million, respectively, in interest. For the year ended December 31, 2011, the Company recognized interest expense of $0.2 million. The Company had approximately $0.1 million and $0.4 million accrued for the payment of interest and penalties at December 31, 2012, and 2011, respectively.

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K. Commitments, Contingencies and Uncertainties

Power Purchase and Sale Contracts

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



						Commercial
						Operation
Type of Contract	Counterparty	Quantity			Term	Date
Power Purchase and Sale Agreement	Freeport		125	MW	December 2008 through December 2013	N/A
Power Purchase and Sale Agreement	Freeport		100	MW	January 2014 through December 2021	N/A
Power Purchase Agreement	Shell	Up to	40	MW	January 2011 through September 2014	N/A
Power Purchase Agreement	NRG		20	MW	August 2011 through August 2031	August 2011
Power Purchase Agreement	Sun Edison 1		10	MW	25 years after operational start date	June 2012
Power Purchase Agreement	Sun Edison 2		12	MW	25 years after operational start date	May 2012
Power Purchase Agreement	Hatch Solar Energy Center I, LLC		5	MW	July 2011 through June 2036	July 2011

The Company has a Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC (“Freeport”) which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2013. The contract was approved by the FERC and continues through December 31, 2021.

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

The Company entered into a 20-year contract with NRG Solar Roadrunner LLC (“NRG”) for the purchase of all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.

The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract which requires a two-year notice to terminate. The Company also provides network integrated transmission service to 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 RGEC.

Environmental Matters

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releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.

Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's ("EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions since 2009. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, such appellate court in August 2012 also vacated the EPA’s proposed replacement, called the Cross-State Air Pollution Rule (“CSAPR”). The EPA is expected to propose a CSAPR replacement rule, which if finalized and upheld, would also replace CAIR. The timing and substance of any final CAIR replacement is currently unknown and until promulgated and upheld, the Company remains subject to CAIR. The annual reconciliation to comply with CAIR is due by March 31 of the following year. The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):



Compliance Year	Amount
2010	$	370
2011	90
2012	37

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

Lease Agreements

The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2014. The Company also has several other leases for office, parking facilities and equipment which expire within the next five years. These lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.

The Company's total annual rental expense related to operating leases was $1.3 million for 2012 and $1.1 million for 2011 and 2010. As of December 31, 2012, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

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2013	$	1,054
2014	1,023
2015	558
2016	511
2017	412

Union Matters

The collective bargaining agreement with existing union employees expires in September 2013 and the Company anticipates entering into negotiations on a new collective bargaining agreement prior to the expiration of the current contract.

L. Litigation

See Note C and Note K for discussion of the effects of government legislation and regulation on the Company.

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M. Employee Benefits

Retirement Plans

The Company’s Retirement Income Plan (the “Retirement Plan”) covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, debt securities and cash equivalents and are managed by professional investment managers appointed by the Company.

The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The other plan, the Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan. The Company complies with FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.

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



	December 31,
	2012						2011
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	$	296,293		$	26,547		$	242,718		$	24,008
Service cost	8,530			299			6,590			260
Interest cost	12,594			963			12,871			1,116
Actuarial loss	12,417			1,338			42,508			2,980
Benefits paid	(8,988		)	(1,906		)	(8,394		)	(1,817		)
Benefit obligation at end of year	320,846			27,241			296,293			26,547
Change in plan assets:
Fair value of plan assets at end of prior year	191,369			—			171,341			—
Actual return on plan assets	20,187			—			16,422			—
Employer contribution	18,000			1,906			12,000			1,817
Benefits paid	(8,988		)	(1,906		)	(8,394		)	(1,817		)
Fair value of plan assets at end of year	220,568			—			191,369			—
Funded status at end of year	$	(100,278	)	$	(27,241	)	$	(104,924	)	$	(26,547	)

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



	December 31,
	2012						2011
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(1,829	)	$	—		$	(1,844	)
Noncurrent liabilities	(100,278		)	(25,412		)	(104,924		)	(24,703		)
Total	$	(100,278	)	$	(27,241	)	$	(104,924	)	$	(26,547	)

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



	December 31,
	2012						2011
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(320,846	)	$	(27,241	)	$	(296,293	)	$	(26,547	)
Accumulated benefit obligation	(274,890		)	(26,363		)	(250,753		)	(26,547		)
Fair value of plan assets	220,568			—			191,369			—

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



	Years Ended December 31,
	2012				2011
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	125,763	$	9,701	$	129,820	$	8,990
Prior service cost	3		314		24		408
Total	$	125,766	$	10,015	$	129,844	$	9,398

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



	December 31,
	2012						2011
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.0	%	3.1	%	4.0	%	4.3	%	3.6	%	4.1	%
Rate of compensation increase	4.8	%	N/A		4.8	%	5.0	%	N/A		5.0	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2012 retirement plans' projected benefit obligation by 12.7%. A 1% decrease in the discount rate would increase the December 31, 2012 retirement plans' projected benefit obligation by 15.7%.

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



	Years Ended December 31,
	2012					2011					2010
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	8,530		$	299	$	6,590		$	260	$	5,888		$	176
Interest cost	12,594			963		12,871			1,116		12,507			1,122
Amendments	—			—		—			—		—			838
Expected return on plan assets	(14,443		)	—		(14,095		)	—		(13,867		)	—
Amortization of:
Net loss	10,729			627		6,190			354		3,331			218
Prior service cost	21			94		21			94		21			94
Net periodic benefit cost	$	17,431		$	1,983	$	11,577		$	1,824	$	7,880		$	2,448

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



	Years Ended December 31,
	2012						2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	6,672		$	1,337		$	40,181		$	2,980		$	12,844		$	1,822
Amortization of:
Net loss	(10,729		)	(627		)	(6,190		)	(354		)	(3,331		)	(218		)
Prior service cost	(21		)	(94		)	(21		)	(94		)	(21		)	(94		)
Total recognized in other comprehensive income	$	(4,078	)	$	616		$	33,970		$	2,532		$	9,492		$	1,510

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



	Years Ended December 31,
	2012				2011				2010
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Total recognized in net periodic benefit cost and other comprehensive income	$	13,353	$	2,599	$	45,547	$	4,356	$	17,372	$	3,958

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2013 (in thousands):



	Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	9,600	$	680
Prior service cost	3		90

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



	2012						2011						2010
			Non-Qualified						Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.3	%	3.6	%	4.1	%	5.4	%	4.6	%	5.3	%	5.9	%	5.2	%	6.0	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		7.5	%	N/A		N/A
Rate of compensation increase	5.0	%	N/A		5.0	%	5.0	%	N/A		5.0	%	5.0	%	N/A		5.0	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2012, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The Company’s target allocations for the plan’s assets are presented below:



	December 31, 2012
Equity securities	55	%
Fixed income	40	%
Alternative investments	5	%
Total	100	%

The Retirement Plan fund includes a diversified portfolio of funds investing in equity securities including large and small capital funds and international funds. The Retirement Plan fund also invests in fixed income securities and a real estate limited partnership. The expected returns for fund investments are based on historical risk premiums above the current fixed income rate, while the expected returns for the fixed income securities are based on the portfolio’s yield to maturity.

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


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


•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of the Guaranteed Investment Contract is based on market interest rates of investments with similar terms and risk characteristics.


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

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The fair value of the Company’s Retirement Plan assets at December 31, 2012 and 2011, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	9,163	$	9,163	$	—	$	—
U.S. Treasury Securities	24,854		24,854		—		—
Guaranteed Investment Contract	1,059		—		1,059		—
Common Stock	52,149		52,149		—		—
Mutual Funds - Fixed Income	59,150		59,150		—		—
Mutual Funds - Equity	65,634		65,634		—		—
Limited Partnership Interest in Real Estate (a)	8,559		—		—		8,559
Total Plan Investments	$	220,568	$	210,950	$	1,059	$	8,559



Description of Securities	Fair Value as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	6,708	$	6,708	$	—	$	—
U.S. Treasury Securities	24,178		24,178		—		—
Guaranteed Investment Contract	608		—		608		—
Common Stock	70,893		70,893		—		—
Mutual Funds - Fixed Income	53,598		53,598		—		—
Mutual Funds - Equity	26,873		26,873		—		—
Limited Partnership Interest in Real Estate (a)	8,511		—		—		8,511
Total Plan Investments	$	191,369	$	182,250	$	608	$	8,511

_____________________

(a)

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

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



	Fair Value of Investments in Real Estate
Balance at December 31, 2010	$	7,757
Unrealized gain in fair value	856
Sale of land	(102		)
Balance at December 31, 2011	8,511
Unrealized gain in fair value	48
Balance at December 31, 2012	$	8,559

There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.

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minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment managers have full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 (“ERISA”) and Department of Labor (“DOL”) regulations.

The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated. The Company expects to contribute $21.8 million to its retirement plans in 2013.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):



	Retirement Income Plan		Non-Qualified Retirement Plans
2013	$	10,021	$	1,829
2014	11,064		1,786
2015	12,143		1,754
2016	13,285		1,794
2017	14,482		1,681
2018-2022	89,697		9,384

Other Postretirement Benefits

The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are no more than the IRS tax deductible limit, as actuarially calculated. The assets of the plan are invested in equity securities, debt securities, and cash equivalents and are managed by professional investment managers appointed by the Company.

The Company determined that the prescription drug benefits of its plan were actuarially equivalent to the Medicare Part D benefit provided for in the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. FASB guidance on accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 requires measurement of the postretirement benefit obligation, the plan assets, and the net periodic postretirement benefit cost to reflect the effects of the subsidy. In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the "Acts"). The Company modified the operations of the plan to conform to the effective provisions of the Acts.

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The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plans (in thousands):



	December 31,
	2012			2011
Change in benefit obligation:
Benefit obligation at end of prior year	$	133,272		$	95,254
Service cost	4,378			2,988
Interest cost	5,651			5,379
Actuarial (gain) loss	(5,009		)	32,694
Benefits paid	(3,929		)	(4,180		)
Retiree contributions	1,086			941
Medicare Part D subsidy	231			196
Benefit obligation at end of year	135,680			133,272
Change in plan assets:
Fair value of plan assets at end of prior year	32,817			33,660
Actual return on plan assets	2,605			—
Employer contribution	3,700			2,200
Benefits paid	(3,929		)	(4,180		)
Retiree contributions	1,086			941
Medicare Part D subsidy	231			196
Fair value of plan assets at end of year	36,510			32,817
Funded status (a)	$	(99,170	)	$	(100,455	)

_____________________


(a)	These amounts are recognized in the Company’s consolidated balance sheets as a non-current liability.

Amounts recognized in accumulated other comprehensive income that have not been recognized as a component of net periodic cost consist of the following (in thousands):



	December 31,
	2012			2011
Net loss	$	13,630		$	20,144
Prior service credit	(24,770		)	(30,647		)
	$	(11,140	)	$	(10,503	)

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



	December 31,
	2012		2011
Discount rate at end of year	4.10	%	4.30	%
Health care cost trend rates:
Initial	7.75	%	8.00	%
Ultimate	4.50	%	4.50	%
Year ultimate reached	2026		2026

The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2012 accumulated postretirement benefit obligation by 14.2%. A 1% decrease in the discount rate would increase the December 31, 2012 accumulated postretirement benefit obligation by 18.1%.

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Net periodic benefit cost is made up of the components listed below (in thousands):



	Years Ended December 31,
	2012			2011			2010
Service cost	$	4,378		$	2,988		$	3,558
Interest cost	5,651			5,379			6,664
Expected return on plan assets	(1,714		)	(1,823		)	(1,529		)
Amortization of:
Prior service benefit	(5,877		)	(5,927		)	(2,869		)
Net loss (gain)	615			(39		)	(175		)
Net periodic benefit cost	$	3,053		$	578		$	5,649

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



	Years Ended December 31,
	2012			2011		2010
Net loss (gain)	$	(5,900	)	$	34,517	$	(4,792	)
Prior service benefit	—			—		(26,605		)
Amortization of:
Prior service benefit	5,877			5,927		2,869
Net (loss) gain	(615		)	39		175
Total recognized in other comprehensive income	$	(638	)	$	40,483	$	(28,353	)

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



	Years Ended December 31,
	2012		2011		2010
Total recognized in net periodic benefit cost and other comprehensive income	$	2,415	$	41,061	$	(22,704	)

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2013 is a prior service benefit of $5.6 million.

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



	2012		2011		2010
Discount rate at beginning of year	4.3	%	5.5	%	5.9	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.2	%
Health care cost trend rates:
Initial	8.0	%	8.5	%	8.5	%
Ultimate	4.5	%	5.0	%	5.0	%
Year ultimate reached	2026		2018		2017

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.

For measurement purposes, an 8.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2012 benefit obligation by $23.5 million

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or $18.7 million, respectively. In addition, such a 1% change would increase or decrease the aggregate 2012 service and interest cost components of the net periodic benefit cost by $2.1 million or $1.6 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2012. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The Company’s target allocations for the plan’s assets are presented below:



	December 31, 2012
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

The asset portfolio includes a diversified mix of funds investing in equity securities including large and small capital funds and international funds. The asset portfolio also includes fixed income securities, cash equivalents, and a real estate limited partnership. The expected returns for fund investments are based on historical risk premiums above the current fixed income rate, while the expected returns for the fixed income securities are based on the portfolio’s yield to maturity.

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


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


•	Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of municipal securities – tax-exempt are reported at fair value based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.


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

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The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2012 and 2011, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	2,075	$	2,075	$	—	$	—
Municipal Securities – Tax Exempt	12,811		—		12,811		—
Common Stock	14,397		14,397		—		—
Mutual Funds – Equity	5,622		5,622		—		—
Limited Partnership Interest in Real Estate (a)	1,605		—		—		1,605
Total Plan Investments	$	36,510	$	22,094	$	12,811	$	1,605

Description of Securities	Fair Value as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	3,000	$	3,000	$	—	$	—
Municipal Securities – Tax Exempt	12,062		—		12,062		—
Common Stock	16,159		16,159		—		—
Limited Partnership Interest in Real Estate (a)	1,596		—		—		1,596
Total Plan Investments	$	32,817	$	19,159	$	12,062	$	1,596

___________________

(a)

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



	Fair Value of Investments in Real Estate
Balance at December 31, 2010	$	1,455
Sale of land	(19		)
Unrealized gain in fair value	160
Balance at December 31, 2011	1,596
Unrealized gain in fair value	9
Balance at December 31, 2012	$	1,605

There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.

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

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The Company expects to contribute $4 million to its other postretirement benefits plan in 2013. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):



2013	$	3,749
2014	4,197
2015	4,698
2016	5,185
2017	5,682
2018-2022	34,806

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Annual matching contributions made to the savings plans for the years 2012, 2011 and 2010 were $1.8 million, $1.7 million, and $1.7 million, respectively.

Annual Short-Term Incentive Plan

The Annual Short-Term Incentive Plan (the “Incentive Plan”) provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on safety, regulatory compliance, and customer satisfaction. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan. In 2012, the Company reached the required levels of earnings per share, safety, regulatory compliance, and customer satisfaction goals for an incentive payment of $7.9 million. The Company reached the required levels of earnings per share, safety, and regulatory compliance goals for an incentive payment of $7.3 million and $7.4 million in 2011 and 2010, respectively. The Company has renewed the Incentive Plan in 2013 with similar goals.

N. Franchises and Significant Customers

El Paso and Las Cruces Franchises

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	July 1, 2005 - August 1, 2010	3.25%
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) The additional fee of 0.75% is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.

Military Installations

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the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. The contract with White Sands expired in 2009 and 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.

O. Financial Instruments and Investments

FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning trust funds are carried at fair value.

Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):



	December 31,
	2012				2011
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	215,228	$	193,135	$	206,756
Senior Notes	696,400		823,497		546,662		700,371
RGRT Senior Notes (1)	110,000		120,985		110,000		116,985
RCF (1)	22,155		22,155		33,379		33,379
Total	$	1,021,690	$	1,181,865	$	883,176	$	1,057,491

__________________

(1)

Nuclear fuel financing as of December 31, 2012 and December 31, 2011 is funded through the $110 million RGRT Senior Notes and $22.2 million and $13.4 million, respectively under the RCF. As of December 31, 2012, there was no amount outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2011, $20.0 million was outstanding under the RCF for working capital and general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting current market rates. Consequently, the carrying value approximates fair value.

Treasury Rate Locks. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6% Senior Notes. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% Senior Notes. In 2013, approximately $0.4 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2012, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the “normal purchases and normal sales” exception provided in FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.

The Company determined that certain of its natural gas commodity contracts with optionality features are not eligible for the normal purchases exception and, therefore, are required to be accounted for as derivative instruments pursuant to FASB guidance for accounting for derivative instruments and hedging activities. However, as of December 31, 2012, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $187.1 million and $168.0 million at December 31, 2012 and 2011, respectively. These

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securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):



	December 31, 2012
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (1):
Federal Agency Mortgage Backed Securities	$	1,792	$	(5	)	$	416	$	(9	)	$	2,208	$	(14	)
U.S. Government Bonds	6,633		(79		)	4,457		(114		)	11,090		(193		)
Municipal Obligations	5,306		(39		)	5,760		(241		)	11,066		(280		)
Corporate Obligations	452		(11		)	—		—			452		(11		)
Total Debt Securities	14,183		(134		)	10,633		(364		)	24,816		(498		)
Common Stock	3,603		(409		)	—		—			3,603		(409		)
Total Temporarily Impaired Securities	$	17,786	$	(543	)	$	10,633	$	(364	)	$	28,419	$	(907	)

____________________


(1)	Includes approximately 65 securities.



	December 31, 2011
	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities (2):
Federal Agency Mortgage Backed Securities	$	515	$	(8	)	$	1,233	$	(23	)	$	1,748	$	(31	)
U.S. Government Bonds	100		(1		)	2,413		(38		)	2,513		(39		)
Municipal Obligations	2,275		(31		)	4,731		(144		)	7,006		(175		)
Corporate Obligations	3,525		(118		)	1,234		(43		)	4,759		(161		)
Total Debt Securities	6,415		(158		)	9,611		(248		)	16,026		(406		)
Common stock	10,688		(2,065		)	1,740		(489		)	12,428		(2,554		)
Total Temporarily Impaired Securities	$	17,103	$	(2,223	)	$	11,351	$	(737	)	$	28,454	$	(2,960	)

______________________


(2)	Includes approximately 96 securities.

The Company monitors the length of time the security trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these securities until their market price recovers, these securities are considered temporarily impaired. The Company will not have a requirement to expend monies held in trust before 2044 or a later period when the Company begins to decommission Palo Verde.

The reported fair values also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands):

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	December 31, 2012				December 31, 2011
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	17,289	$	1,036	$	25,077	$	1,220
U.S. Government Bonds	13,295		678		10,263		972
Municipal Obligations	22,797		1,531		30,310		1,792
Corporate Obligations	12,378		1,134		7,641		459
Total Debt Securities	65,759		4,379		73,291		4,443
Common Stock	73,210		22,839		62,479		15,681
Mutual Funds - Equity	15,194		1,821		—		—
Cash and Cash Equivalents	4,471		—		3,739		—
Total	$	158,634	$	29,039	$	139,509	$	20,124

The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company’s mortgage-backed securities, based on contractual maturity, are due in 10 years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from 3 years to 7 years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2012 is as follows (in thousands):



	Total		2013		2014 through 2017		2018 through 2022		2023 and Beyond
Municipal Debt Obligations	$	33,863	$	2,326	$	12,223	$	14,483	$	4,831
Corporate Debt Obligations	12,830		432		4,653		3,991		3,754
U.S. Government Bonds	24,385		3,174		7,287		8,605		5,319

The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. For the twelve months ended December 31, 2012, 2011, and 2010 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):



	2012			2011			2010
Gross unrealized holding losses included in pre-tax income	$	(479	)	$	(2,116	)	$	(263	)

The Company’s marketable securities in its decommissioning trust funds are sold from time to time, and the Company uses the specific identification basis on which to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2012, 2011, and 2010 and the related effects on pre-tax income are as follows (in thousands):



	2012			2011			2010
Proceeds from sales or maturities of available-for-sale securities	$	98,542		$	82,926		$	61,656
Gross realized gains included in pre-tax income	$	1,478		$	1,479		$	1,030
Gross realized losses included in pre-tax income	(2,041		)	(721		)	(889		)
Gross unrealized losses included in pre-tax income	(479		)	(2,116		)	(263		)
Net losses in pre-tax income	$	(1,042	)	$	(1,358	)	$	(122	)
Net unrealized holding gains included in accumulated other comprehensive income	$	9,927		$	1,570		$	6,665
Net losses reclassified out of accumulated other comprehensive income	1,042			1,358			122
Net gains in other comprehensive income	$	10,969		$	2,928		$	6,787

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Fair Value Measurements. FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the consolidated balance sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market.

•

Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.


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

The securities in the Company’s decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. FASB guidance identifies this valuation technique as the “market approach” with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other than temporary.

The fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2012 and 2011, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2012		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,295	$	—	$	—	$	1,295
Available for sale:
U.S. Government Bonds	$	24,385	$	24,385	$	—	$	—
Federal Agency Mortgage Backed Securities	19,497		—		19,497		—
Municipal Bonds	33,863		—		33,863		—
Corporate Asset Backed Obligations	12,830		—		12,830		—
Subtotal, Debt Securities	90,575		24,385		66,190		—
Common Stock	76,813		76,813		—		—
Mutual Funds - Equity	15,194		15,194		—		—
Cash and Cash Equivalents	4,471		4,471		—		—
Total available for sale	$	187,053	$	120,863	$	66,190	$	—

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Description of Securities	Fair Value as of December 31, 2011		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Trading Securities:
Investments in Debt Securities	$	1,120	$	—	$	—	$	1,120
Available for sale:
U.S. Government Bonds	$	12,776	$	12,776	$	—	$	—
Federal Agency Mortgage Backed Securities	26,825		—		26,825		—
Municipal Bonds	37,316		—		37,316		—
Corporate Asset Backed Obligations	12,400		—		12,400		—
Subtotal, Debt Securities	89,317		12,776		76,541		—
Common Stock	74,907		74,907		—		—
Cash and Cash Equivalents	3,739		3,739		—		—
Total available for sale	$	167,963	$	91,422	$	76,541	$	—

Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):



	2012		2011
Balance at January 1	$	1,120	$	2,909
Sale of debt security	—		(2,000		)
Realized gain on sale of debt security (a)	—		431
Net unrealized gains (losses) in fair value recognized in income on debt securities still held (a)	175		(220		)
Balance at December 31	$	1,295	$	1,120

_____________________

(a) These amounts are reflected in the Company's consolidated statement of operations as investment and interest income.

There were no transfers in and out of Level 1 and Level 2 fair value measurements categories during the twelve month periods ending December 31, 2012 and 2011. There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.

P. Supplemental Statements of Cash Flows Disclosures



	Years Ended December 31,
	2012		2011			2010
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	50,189	$	48,797		$	47,783
Income taxes paid (refund), net	5,031		(6,260		)	7,343
Non-cash financing activities:
Grants of restricted shares of common stock	2,411		3,268			2,098
Issuance of performance shares	1,193		628			663
Acquisition of treasury stock for options exercised	—		500			—

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Q. Selected Quarterly Financial Data (Unaudited)

The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.



	2012 Quarters								2011 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	188,802	$	267,249	$	228,252	$	168,578	$	191,663	$	307,633	$	242,605	$	176,112
Operating income	13,708		86,396		56,512		12,042		15,994		102,215		58,121		14,473
Net income	4,819		51,789		30,894		3,344		5,453		58,321		32,990		6,775
Basic earnings per share:
Net income	0.12		1.29		0.77		0.08		0.14		1.41		0.78		0.16
Diluted earnings per share:
Net income	0.12		1.29		0.77		0.08		0.13		1.40		0.78		0.16
Dividends declared per share of common stock	0.25		0.25		0.25		0.22		0.22		0.22		0.22		—

________________


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

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

None.


Item 9A.	Controls and Procedures

Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities and Exchange act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2012, our disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal Control over Financial Reporting is included herein under the caption “Management Report on Internal Control Over Financial Reporting” on page 39 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2012, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.


Item 9B.	Other Information

None.

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PART III


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

Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2013 Annual Meeting of Shareholders (the “2013 Proxy Statement”) under the heading “Nominees and Directors of the Company.” Information regarding executive officers, included herein under the caption “Executive Officers of the Registrant” in Part I, Item 1 above, is incorporated herein by reference.

The information concerning the identification of our standing audit committee required by this Item is incorporated by reference from the 2013 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation and Committees,” and under the heading “Audit Committee Report.”

The information concerning our audit committee financial experts required by this Item is incorporated by reference from the 2013 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation and Committees.”

The information concerning compliance with Section 16(a) of the Exchange Act required by this Item is incorporated by reference from the 2013 Proxy Statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance.”

We have adopted a Code of Ethics that is incorporated by reference from the 2013 Proxy Statement under the caption “Business Conduct Policies” under the heading “Corporate Governance.”


Item 11.	Executive Compensation

Incorporated herein by reference from the 2013 Proxy Statement under the heading “Summary of Compensation.”


Item 12.	Security Ownership of Certain Beneficial Management

Incorporated herein by reference from the 2013 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”

Equity Compensation Plan Information



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans
approved by security holders	15,000	$	12.78	623,918
Equity compensation plans
not approved by security holders	—	—		—
Total	15,000	$	12.78	623,918


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

Incorporated herein by reference from the 2013 Proxy Statement under the heading “Certain Relationships and Related Party Transactions.”


Item 14.	Principal Accounting Fees and Services

Incorporated herein by reference from the 2013 Proxy Statement under the heading “Independent Registered Public Accounting Firm.”

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PART IV


Item 15.	Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report:



		Page
1.	Financial Statements:

	See Index to Financial Statements	41

2.	Financial Statement Schedules:

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

3.	Exhibits

Certain of the following documents are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.

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

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Exhibit Number		Title
	4.15	–	Remarketing and Purchase Agreement dated August 1, 2012 among El Paso Electric Company and U.S. Bancorp Investments, Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.16	–	Tender Agreement dated August 1, 2012 between El Paso Electric Company and Union Bank, N.A., relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.03 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.17	–	Amended and Restated Installment Sale Agreement, dated as of August 1, 2012, between El Paso Electric Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.18	–	Ordinance No. 2012-1256 adopted by the City Council of Farmington, New Mexico on June 12, 2012 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 in aggregate principal amount of its Pollution Control Revenue Refunding Bonds, 2012 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.01 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.19	–	Debt Securities Indenture, dated as of May 1, 2005. (Exhibit 4.1 to the Company's Current Report on Form 8-K, dated May 17, 2005)
	4.20	–	First Supplemental Indenture, dated as of May 19, 2008. (Exhibit 4.4 to the Company's Registration Statement on Form S-3, dated May 20, 2008)
	4.21	–	Securities Resolution No. 1, dated May 11, 2005, relating to the Company's 6.00% Senior Notes due 2035. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated May 17, 2005)
	4.22	–	Securities Resolution No. 2, dated May 29, 2008, relating to the Company's 7.50% Senior Notes due 2038. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated June 3, 2008)
	4.23	–	Securities Resolution No. 3, dated December 3, 2012, relating to the Company's 3.30% Senior Notes due 2022. (Exhibit 4.01 to the Company's Current Report on Form 8-K dated December 6, 2012)
	4.24	–	Bond Purchase Agreement dated August 15, 2012, among Maricopa County, Arizona Pollution Control Corporation, U.S. Bancorp Investments, Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated, relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
Exhibit 10 – Material Contracts:
	10.01	–	Co-Tenancy Agreement, dated July 19, 1966, and Amendments No. 1 through 5 thereto, between the Participants of the Four Corners Project, defining the respective ownerships, rights and obligations of the Parties. (Exhibit 10.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.01-01		–	Amendment No. 6, dated February 3, 2000, to Exhibit 10.01. (Exhibit 10.01-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
	10.02	–	Supplemental and Additional Indenture of Lease, dated May 27, 1966, including amendments and supplements to original Lease Four Corners Units 1, 2 and 3, between the Navajo Tribe of Indians and Arizona Public Service Company, and including new Lease Four Corners Units 4 and 5, between the Navajo Tribe of Indians and Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company. (Exhibit 4-e to Registration Statement No. 2-28692 on Form S-9)
10.02-01		–	Amendment and Supplement No. 1, dated March 21, 1985, to Exhibit 10.02. (Exhibit 19.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1985)
	10.03	–	El Paso Electric Company 1996 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-17971 on Form S-8)
	10.04	–	Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.04-01		–	Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)
10.04-02		–	Amendment No. 12, dated February 3, 2000, to Exhibit 10.04. (Exhibit 10.04-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

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Exhibit Number		Title
	10.05	–	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.05-01		–	Amendment No. 14, dated June 20, 2000, to Exhibit 10.05. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.05-02		–	Amendment No. 15, dated January 13, 2011, to the Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	10.06	–	ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.07	–	Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)
10.07-01		–	Amendment No. 1, dated November 20, 1986, to Exhibit 10.07. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
	10.08	–	Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)
	10.09	–	Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.10	–	Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.11	–	El Paso Electric Company Excess Benefit Plan, dated as of December 31, 2008. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	10.12	–	Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
	10.13	–	Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.13-01		–	Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.13. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	10.14	–	Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.14-01		–	Settlement Agreement between TEP and the Company, dated April 26, 2011, to Exhibit 10.14. (Exhibit 10.14-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
	10.15	–	Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
	10.16	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)

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Exhibit Number		Title
*10.17		–	Form of Indemnity Agreement, between the Company and its directors and officers.
	10.18	–	Interchange Agreement, executed April 14, 1982, between Comisión Federal de Electricidad and the Company. (Exhibit 19.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1991)
	10.19	–	Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.20	–	Purchase Contract, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.20-01		–	Second Amendment, dated as of July 12, 2007, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007)
10.20-02		–	Third Amendment, dated as of August 17, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.20-03		–	Fourth Amendment, dated as of September 23, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
	10.21	–	Note Purchase Agreement, dated as of August 17, 2010, between El Paso Electric Company, Rio Grande Resources Trust II and the purchasers named therein. (Exhibit 10.1 to the Company’s Form 8-K, dated as of August 17, 2010)
	10.22	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 1. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.23	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 2. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.24	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 3. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.25	–	Credit agreement dated as of September 23, 2010, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party hereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.25-01		–	Amended and Restated Credit Agreement dated as of November 15, 2011, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party hereto, JP Morgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent.
10.25-02		–	Incremental Facility Assumption Agreement dated as of March 29, 2012, related to the Amended and Restated Credit Agreement, referred to in Exhibit 10.25-01, among the Company and The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as issuing bank and as administrative agent and Union Bank, N.A., as syndication agent. (Exhibit 10.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012)
†10.26		–	Amended and Restated Change in Control Agreement between the Company and certain key officers of the Company. (Exhibit 9.1 to the Company’s Form 8-K as of March 20, 2007)
	10.27	–	Reserved
††10.28		–	Form of Stock Option Agreement between the Company and certain key officers of the Company. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
†††10.29		–	Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.30		–	Reserved
	10.31	–	El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)

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Exhibit Number		Title
	10.32	–	Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
	10.33	–	Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
	10.34	–	Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001)
	10.35	–	Shiprock – Four Corners Project 345 kV Switchyard Interconnection Agreement, dated March 6, 2002. APS Contract No. 51999. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002)
	10.36	–	Interconnection Agreement dated as of May 23, 2002, between the Company and the Public Service Company of New Mexico. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
10.36-01		–	First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.36. (Exhibit 10.52.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003)
	10.37	–	Reserved
	10.38	–	Credit agreement dated as of April 11, 2006, among the Company, JPMorgan Chase Bank, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II, the lenders party hereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank of California, N.A., as syndication agent. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.38-01		–	Incremental Facility Assumption Agreement, dated as of July 12, 2007, related to the Credit Agreement referred to in Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. (Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007)
	10.39	–	Eight Treasury Rate Lock agreements between the Company and Credit Suisse First Boston International. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
††††10.40		–	Master Power Purchase and Sale Agreement and Transaction Agreement, dated as of July 7, 2004, between the Company and Southwestern Public Service Company. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
	10.41	–	Reserved
	10.42	–	Power Purchase and Sale Agreement, dated as of December 16, 2005, between the Company and Phelps Dodge Energy Services, LLC. (Exhibit 10.42 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005)
10.42-01		–	Letter Agreement, dated June 3, 2008, to Exhibit 10.42.
10.42-02		–	Letter Agreement, dated November 26, 2008, to Exhibit 10.42.
10.42-03		–	Letter Agreement, dated November 12, 2010, to Exhibit 10.42.
10.42-04		–	Letter Agreement, dated April 29, 2011, to Exhibit 10.42. (Exhibit 10.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011)
	10.43	–	Settlement Agreement between the State of Texas and the Company, dated as of October 17, 2006. (Exhibit 10.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006)
††††10.44		–	Confirmation of Power Purchase Transaction, dated April 18, 2007, between the Company and Credit Suisse Energy LLC. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)
††††10.44-01		–	Amended Confirmation of Power Purchase Transaction, dated September 3, 2008, between the Company and Credit Suisse Energy LLC. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008)
††††10.44-02		–	Amended Confirmation of Power Purchase Transaction, dated March 30, 2009, between the Company and Credit Suisse Energy LLC. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
††††10.45		–	Confirmation of Power Sales Transaction, dated April 18, 2007, between the Company and Imperial Irrigation District. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2007)
††††10.45-01		–	Amended Confirmation of Power Sales Transaction, dated August 29, 2008, between the Company and Imperial Irrigation District. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008)

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Exhibit Number		Title
††††10.45-02		–	Amended Confirmation of Power Sales Transaction, dated March 31, 2009, between the Company and Imperial Irrigation District. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	10.46	–	Reserved
	10.47	–	Reserved
	10.48	–	El Paso Electric Company 2007 Long-Term Incentive Plan. (Exhibit 10.1 to the Company’s Form 8-K, dated as of May 2, 2007)
	10.49	–	Employment Agreement between the Company and David W. Stevens, dated November 12, 2008.
10.49-01		–	Amended and Restated Employment Agreement between the Company and David W. Stevens, dated March 2, 2011. Amendment to Exhibit 10.49 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010. (Exhibit 10.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011)
	10.50	–	Separation Agreement between the Company and Richard G. Fleager dated April 2, 2012. (Exhibit 10.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012)
	10.51	–	Employment Agreement between the Company and Thomas V. Shockley, III, dated June 1, 2012. (Exhibit 10.05 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012)
Exhibit 12 – Computation of Ratios:
*12.01		–	Computation of Ratios of Earnings to Fixed Charges
Exhibit 21 – Subsidiaries of the Company:
	21.01	–	MiraSol Energy Services, Inc., a Delaware corporation
Exhibit 23 – Consent of Experts:
*23.01		–	Consent of KPMG LLP (set forth on page 105 of this report)
Exhibit 24 – Power of Attorney:
*24.01		–	Power of Attorney (set forth on page 103 of the Original Form 10-K)
*24.02		–	Certified copy of resolution authorizing signatures pursuant to Power of Attorney
Exhibit 31 and 32 – Certifications:
*31.01		–	Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.01		–	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99 – Additional Exhibits:
	99.01	–	Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to Registration Statement No. 33-99744 on Form S-1)
	99.02	–	Reserved
	99.03	–	Final Order, entered September 24, 1998, by the New Mexico Public Utility Commission. (Exhibit 99.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
	99.04	–	Final Order, entered June 8, 1999, by the Public Utility Commission of Texas. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	99.05	–	Final Order, entered January 8, 2002, by the New Mexico Public Utility Commission. (Exhibit 99.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
	99.06	–	News Release, dated as of December 5, 2002, by the El Paso Electric Company announcing settlement with the FERC Trial Staff. (Exhibit 99.01 to the Company’s Form 8-K, dated as of December 6, 2002)
	99.07	–	“Stipulated Facts and Remedies,” dated as of December 5, 2002, to be filed by the FERC Trial Staff as part of its written testimony. (Exhibit 99.02 to the Company’s Form 8-K, dated as of December 6, 2002)
Exhibit 101 – XBRL – Related Documents:
*101.INS		–	XBRL Instance Linkbase Document
*101.SCH		–	XBRL Taxonomy Extension Schema Linkbase Document
*101.CAL		–	XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		–	XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		–	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		–	XBRL Taxonomy Extension Presentation Linkbase Document

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	*			Filed herewith.
	†			Twelve agreements, substantially identical in all material respects to this exhibit, have been entered into with David G. Carpenter; Steven P. Busser; Steven T. Buraczyk; Robert C. Doyle; Nathan T. Hirschi; Mary E. Kipp; Kerry B. Lore; Rocky R. Miracle; Hector R. Puente; Andres R. Ramirez; Henry Wayne Soza; and Guillermo Silva, Jr., officers of the Company.
	††			One agreement, dated as of December 4, 2003, identical in all material respects to this Exhibit, has been entered into with Steven P. Busser; officer of the Company.
				In lieu of non-employee director cash compensation, twelve agreements, dated as of January 1, 2011, April 1, 2011, and July 1, 2011, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Kenneth R. Heitz, and Patricia Z. Holland-Branch; directors of the Company.
				In lieu of non-employee director cash compensation, twelve agreements, dated as of October 1, 2011, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, and Stephen N. Wertheimer; directors of the Company.
	†††			In lieu of non-employee director cash compensation, nine agreements, dated as of January 1, 2012, April 1, 2012 and July 1, 2012, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Patricia Z. Holland‑Branch; and Stephen N. Wertheimer directors of the Company.
				In lieu of non-employee director cash compensation, four agreements, dated as of October 1, 2012, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, Michael K. Parks; and Stephen N. Wertheimer; directors of the Company.
				In lieu of non-employee director cash compensation, eleven agreements, dated as of May 26, 2011, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland‑Branch; Michael K. Parks; Thomas V. Shockley, III; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
				In lieu of non-employee director cash compensation, ten agreements, dated as of May 31, 2012, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland‑Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
	††††			Confidential treatment has been requested and received for the redacted portions of these Exhibits. The copies filed omit the information subject to the confidentiality request. Omissions are designated as “****.” A complete version of these Exhibits has been filed separately with the Securities and Exchange Commission.

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UNDERTAKING

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

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POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints Thomas V. Shockley III, David G. Carpenter and Mary E. Kipp, its, his or her true and lawful attorneys-in-fact and agents, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of February 2013.



EL PASO ELECTRIC COMPANY

By:	/s/ THOMAS V. SHOCKLEY III
	Thomas V. Shockley III
	Chief Executive Officer (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.



Signature	Title	Date

/s/ THOMAS V. SHOCKLEY III	Chief Executive Officer (Principal Executive Officer)	February 25, 2013
(Thomas V. Shockley III)	Chief Executive Officer (Principal Executive Officer)

/s/ DAVID G. CARPENTER	Senior Vice President and Chief Financial Officer (Principal Financial Officer )	February 25, 2013
(David G. Carpenter)

/s/ NATHAN T. HIRSCHI	Vice President and Controller	February 25, 2013
(Nathan T. Hirschi)

/s/ CATHERINE A. ALLEN	Director	February 25, 2013
(Catherine A. Allen)

/s/ JOHN ROBERT BROWN	Director	February 25, 2013
(John Robert Brown)

/s/ JAMES W. CICCONI	Director	February 25, 2013
(James W. Cicconi)

/s/ EDWARD ESCUDERO	Director	February 25, 2013
(Edward Escudero)

/s/ JAMES W. HARRIS	Director	February 25, 2013
(James W. Harris)

/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 25, 2013
(Patricia Z. Holland-Branch)

/s/ WOODLEY L. HUNT	Director	February 25, 2013
(Woodley L. Hunt)

/s/ MICHAEL K. PARKS	Director	February 25, 2013
(Michael K. Parks)

/s/ ERIC B. SIEGEL	Director	February 25, 2013
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 25, 2013
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 25, 2013
(Charles A. Yamarone)

104