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, 2011

OR

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

For the transition period from to

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)

Texas	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, 2011, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,330,697,564 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2012, there were 40,119,381 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 2012 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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 II
TEP	Tucson Electric Power Company
TNP	Texas-New Mexico Power Company

(i)

TABLE OF CONTENTS

Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	19
1B	Unresolved Staff Comments	22
2	Properties	23
3	Legal Proceedings	23
4	Removed and Reserved	23
	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
6	Selected Financial Data	27
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
7A	Quantitative and Qualitative Disclosures About Market Risk	44
8	Financial Statements and Supplementary Data	46
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
9A	Controls and Procedures	100
9B	Other Information	100
	PART III
10	Directors, Executive Officers and Corporate Governance	101
11	Executive Compensation	101
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	101
13	Certain Relationships and Related Transactions, and Director Independence	101
14	Principal Accounting Fees and Services	101
	PART IV
15	Exhibits and Financial Statement Schedules	102

(ii)

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” 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 rates in Texas following the rate case filed on February 1, 2012 pursuant to the El Paso City Council's resolution ordering us to show cause why our base rates for El Paso customers should not be lower,

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

• 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 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,

• 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,

• political, legislative, judicial and regulatory developments,

(iii)

• 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, 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 1,785 MW. For the year ended December 31, 2011, the Company’s energy sources consisted of approximately 45% nuclear fuel, 30% natural gas, 6% coal, 19% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 380,000 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 63% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2011). 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 refining, 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, 2012, the Company had approximately 1,000 employees, 41% 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, 2011, the Company’s net dependable generating capability of 1,785 MW consists of the following:

Station	Primary Fuel Type	Net Dependable Generating Capability * (MW)
Palo Verde Station	Nuclear	633
Newman Power Station	Natural Gas	752
Rio Grande Power Station	Natural Gas	229
Four Corners Station	Coal	108
Copper Power Station	Natural Gas	62
Hueco Mountain Wind Ranch	Wind	1
Total		1,785

____________________

* During summer peak period.

Palo Verde Station

The Company owns a 15.8% interest, or approximately 633 MW, in the three nuclear generating units and common facilities (“Common Facilities”) at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company (“SCE”), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District (“SRP”) and the Los Angeles Department of Water and Power. APS serves as operating agent for Palo Verde, and under the Arizona Nuclear Power Project ("ANPP") Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde.

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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 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.

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 will now expire in 2045, 2046 and 2047, respectively. For the last three quarters of 2011 combined, the extension of the operating licenses 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. The Company is required to maintain a minimum accumulation and a minimum 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, 2011, the Company’s decommissioning trust fund had a balance of $168.0 million, and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.

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 increase in the license life 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 will lower annual expenses in the future. 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. See “Spent Fuel Storage” and “Disposal of Low-Level Radioactive Waste” below.

Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the on-site facilities until accepted by the DOE for permanent disposal. The 2010 Study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2057. APS believes 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.

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 has previously reported that its spent nuclear fuel disposal facilities would not be in operation in the near future. In November 1997, the United States Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. The Company cannot predict when spent fuel shipments to the DOE will commence.

The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde that 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.

In December 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. APS pursued a damages claim for costs incurred through December 2006 in a trial that began on January 28, 2009. On June 18, 2010, the court

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awarded APS and the other Palo Verde Participants approximately $30 million. 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. APS is continuing to pursue settlement of damage claims for costs incurred after 2006.

Disposal of Low-level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. The construction and opening of low-level radioactive waste disposal sites have been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed sites. The opposition, delays, uncertainty and costs that have been experienced demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.

Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant's required licensing and design parameters. Validation of that data will continue as more information becomes available.

Following the March 11, 2011 earthquake and tsunami in Japan, the NRC launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force's recommendations.

On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

Until further action is taken by the NRC as a result of this event, the Company cannot predict any 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 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 $2.75 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 $9.57 million for the current policy period.

Newman Power Station

The Company's Newman Power Station, located in El Paso, Texas, consists of three steam‑electric generating units and two combined cycle generating units, including a 278 MW combined cycle generating unit designated as Newman Unit 5. Construction of Newman Unit 5 began in July 2008 and was completed in two phases. The first phase, consisting of two 70 MW gas turbine generators, was completed in May 2009. The second phase consisted of the addition of two heat recovery steam generators and a steam turbine with a net peak period capability of 138 MW and was made commercially available in April 2011. The current aggregate net capability of the Newman Power Station is approximately 752 MW. The station operates primarily on natural gas but can also operate on fuel oil.

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Rio Grande Power Station

The Company's Rio Grande Power Station, located in Sunland Park, New Mexico, adjacent to El Paso, Texas, consists of three steam-electric generating units with an aggregate net peak period capability of approximately 229 MW. The units operate on natural gas. Construction has begun on Rio Grande Unit 9 to add an aeroderivative unit with a net dependable generating capacity of 87MW that should reach commercial operation by May 2013.

Four Corners Station

The Company owns a 7% interest, or approximately 108 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. Each of the two coal-fired generating units has a total net peak period capability of 770 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants, PNM, TEP, SCE and SRP.

Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016, with a one-time option to extend the term for an additional 25 years. Certain of the facilities associated with Four Corners, including transmission lines and almost all of the contracted coal sources, are also located on Navajo land. Units 4 and 5 are located adjacent to a surface-mined supply of coal.

APS, on behalf of the Four Corners participants, has negotiated amendments to the existing facility lease with the Navajo Nation that would extend the Four Corners leasehold interest to 2041. Execution by the Navajo Nation of the lease amendments is a condition to closing of a purchase by APS of SCE's interests in Four Corners. The execution of these amendments by the Navajo Nation require the approval of the Navajo Nation Council and the Nation's President, which occurred in February and March 2011. The effectiveness of the amendments also requires the approval of the Department of the Interior ("DOI"), as does a related Federal rights-of-way grant which the Four Corners participants will pursue. A Federal environmental review will be conducted as part of the DOI review process.

Copper Power Station

The Company’s Copper Power Station, located in El Paso, Texas, consists of a 62 MW combustion turbine used primarily to meet peak demand. The unit operates on natural gas.

Hueco Mountain Wind Ranch

The Company’s Hueco Mountain Wind Ranch, located in Hudspeth County, east of El Paso County and adjacent to Horizon City, 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.

Springerville-Macho Springs-Luna-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEP's Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico. This line also contains two other substations; the Macho Springs Substation near Hatch, New Mexico, and the Luna Substation near Deming, New Mexico. This transmission line provides an interconnection with TEP for delivery of the Company's generation entitlements from Palo Verde and, if necessary, Four Corners. The Macho Springs Substation was commissioned in 2011 to interconnect a wind farm that provides renewable power to TEP.

West Mesa-Arroyo Line. The Company owns a 202-mile, 345 kV transmission line from PNM's West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico. West Mesa Substation is the primary delivery point for the Company's generation entitlement from Four Corners, which is transmitted from Four Corners to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.

Greenlee-Hidalgo-Luna-Newman Line. The Company owns 40% of a 60-mile, 345 kV transmission line between TEP's

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Greenlee Substation near Duncan, Arizona to the Hidalgo Substation near Lordsburg, New Mexico, approximately 57% of a 50-mile, 345 kV transmission line between the Hidalgo Substation and the Luna Substation and 100% of an 86-mile, 345 kV transmission line between the Luna Substation and the Newman Power Station. These lines provide an interconnection with TEP for delivery of the Company's entitlements from Palo Verde and, if necessary, Four Corners. The Company owns the Afton 345 kV Substation located approximately 57 miles from the Luna Substation on the Luna-to-Newman portion of the line. The Afton Substation interconnects a generator owned and operated by PNM.

Eddy County-AMRAD Line. The Company owns 66.7% of a 125‑mile, 345 kV transmission line 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. The Company also owns 66.7% of the terminal. This terminal enables the Company to connect its transmission system to that of SPS (a subsidiary of Xcel Energy), providing the Company with access to purchased and emergency power from SPS and power markets to the east.

Palo Verde Transmission and Switchyard. The Company owns 18.7% of two 45-mile, 500 kV lines from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona. The Company also owns 18.7% of a 75-mile, 500 kV line from Palo Verde to the Jojoba Substation, then to the Kyrene Substation located near Tempe, Arizona. These lines provide the Company with a transmission path for delivery of power from Palo Verde. The Company owns 14.94% and 9.35% respectively of two 500 kV switchyards connected to the Palo Verde-Kyrene 500 kV line: the Hassayampa switchyard, adjacent to the southern edge of the Palo Verde 500 kV switchyard and the Jojoba switchyard approximately 24 miles from Palo Verde. These switchyards were built to accommodate the addition of new generation and transmission in the Palo Verde area.

Environmental Matters

General. The Company is subject to laws and regulations with respect to air, soil and water quality, waste disposal and other environmental matters by federal, state, regional, tribal and local authorities. Those authorities govern facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these requirements can result in actions by regulatory agencies or other authorities 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 and regulations are subject to change and, as a result of those changes, 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”) 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. 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 from the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions starting in 2009. The U.S. Court of Appeals for the District of Columbia voided CAIR in 2008; however, the Company has complied with CAIR since 2009, and such rule is binding. 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		62

Cross-State Air Pollution Rule. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which is intended to replace CAIR. CSAPR requires 28 states, including Texas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were required to begin January 1, 2012, with further reductions required beginning January 1, 2014. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay CSAPR, including the supplemental final rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. The court is scheduled to hear the cases against the rule in April 2012. Under this timeframe, the court could issue its decision by summer or early fall 2012. As the outcome of the judicial review and any other legal or Congressional challenges are uncertain, the Company is unable to determine what impact CSAPR may ultimately have on its operations and consolidated financial results, but it could be material. Until the legal challenges to CSAPR are resolved, the Company's obligations under CAIR remains in effect.

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, CO and SO₂.

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Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. The Company is currently evaluating what impact this 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. In addition, the EPA is currently reviewing the PM NAAQS. The Company cannot at this time predict the impact of this review and any possible new standards on its operations or consolidated financial results, but it could be material. The EPA had been in the process of revising the NAAQS for ozone. However, in September 2011, President Obama ordered the EPA to withdraw its proposal. Work, however, is underway to support EPA's planned reconsideration of the standards in 2013.

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 power plants, which replaces the prior federal Clean Air Mercury Rule and requires significant reductions in emissions of mercury and other air toxics. Companies impacted by the new standards will have up to four (and in certain cases five) years to comply. The Company is currently evaluating the new standards and cannot at this time determine the impact they may have on its Four Corners plant, but the cost of compliance could be material.

Climate Change. 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 (“GHG”) emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of GHGs, such as carbon dioxide, could impose significant costs or limitations on the Company. In recent years, the U.S. Congress has considered new legislation to restrict or regulate GHG emissions, although federal efforts directed at enacting comprehensive climate change legislation stalled in 2010 and appear unlikely to recommence in the near future. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered by Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In September 2009, the EPA adopted a rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. GHG emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company's fossil fuel-fired power generating assets are subject to this rule, and the first report containing 2010 emissions was submitted to the EPA prior to the September 30, 2011 due date. The Company also has inventoried and implemented procedures for electrical equipment containing sodium hexafluoride ("SF6"), another GHG. The Company is tracking these GHG emissions pursuant to the EPA's new SF6 reporting rule that was finalized in late 2010 and became effective January 1, 2011. The first report to EPA under this rule was originally due on March 31, 2012, but in November 2011, EPA delayed its submittal to September 26, 2012.

The EPA has also proposed and finalized other rulemakings on GHG emissions that affect electric utilities. Under EPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications (referred to as the “PSD” program). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or 100,000 tons per year, depending on various factors), will be required to implement “best available control technology,” or “BACT”. Pursuant to the rule, the EPA may reduce the 75,000 tons threshold referenced above in 2012 or thereafter. The EPA has issued guidance on what BACT entails for the control of GHGs, and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of these new regulations on the Company's operations cannot be determined at this time, but the cost of compliance with new regulations could be material. Also, on December 23, 2010, the EPA announced a settlement agreement with states and environmental groups regarding setting new source performance standards for GHG emissions from new and existing coal-, gas- and oil-based power plants. Pursuant to this agreement, and certain agreed upon extensions, the EPA intends to issue proposed rules for new and modified electric generating units ("EGUs") in 2012. It is unclear when the EPA will propose a GHG New Source Performance Standard ("NSPS") for existing EGUs and how stringent it would be, but this rule is expected. The impact of these rules on the Company is unknown at this time, but they could result in significant costs.

In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to consider how to address GHG emissions and are actively considering the development of emission inventories or regional GHG cap and trade programs.

6

It is not currently possible to predict with confidence how any pending, proposed or future GHG legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact the Company's business. However, any such legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or reduced demand for the power the Company generates, could require the Company to purchase rights to emit GHG, and 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 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. Substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. 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 at present to meaningfully quantify the costs of these potential impacts.

Contamination Matters. The Company has a provision for environmental remediation obligations of approximately $0.3 million at December 31, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community reservation in Arizona and designated it as a Superfund site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has an agreement with the EPA and a former property owner to resolve this matter and on June 30, 2011, the Company entered into a consent decree with the EPA at a cost to the Company of less than $0.1 million.

Environmental Litigation and Investigations. On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the CAA. APS responded to this request in 2009. The Company is unable to predict the timing or content of the EPA's response, if any, or any resulting actions.

The Company received word 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 provisions of the CAA. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's 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 NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS advised that it believes the claims in this matter are without merit and will vigorously defend against them. The Company is unable to predict the outcome of these alleged violations.

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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, the costs of which are included in the table below.

The Company’s estimated cash construction costs for 2012 through 2016 are approximately $1.4 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)
2012	$	242	Production (1)(2)	$	892
2013	232		Transmission	120
2014	267		Distribution	281
2015	311		General	96
2016	337
Total	$	1,389	Total	$	1,389

 __________________________

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

(2) $700 million has been allocated for new generating capacity including $38 million to complete Rio Grande Unit 9, $186 million to construct two 87 MW gas-fired LMS-100 units that are scheduled to come on line in 2014 and 2015, $174 million for two 87 MW gas-fired LMS-100 units scheduled to come on line in 2016, and $284 million of initial expenditures for two additional 292 MW combined cycle generating units that are anticipated to come on line in 2018 and 2019 and $18 million for anticipated renewable projects to be built in El Paso. Total production expenditures also include $24 million for other local generation, $14 million for the Four Corners Station and $154 million for the Palo Verde Station.

8

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	2011		2010		2009
Nuclear	45	%	45	%	45	%
Natural gas	30		27		22
Coal	6		6		7
Purchased power	19		22		26
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 95% of Palo Verde's requirements for uranium concentrates through 2015, 90% of its requirements in 2016-2017 and 80% of its requirements in 2018. The participants have also contracted for all of Palo Verde's conversion services through 2015 and 95% of its requirements in 2016-2018, 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 a $200 million RCF for the financing of nuclear fuel and for working capital and general corporate purposes. On November 15, 2011, the Company, along with RGRT, refinanced and extended the credit facility, which includes an option, subject to lenders' approval, to expand the size to $300 million. The amended facility reduces our borrowing costs and extends the maturity from September 2014 to September 2016. The total amount borrowed for nuclear fuel by RGRT at December 31, 2011 was $123.4 million of which $13.4 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 2011, 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 2012. 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. The intrastate natural gas agreement was amended effective September 1, 2010.

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. In June 2010, the Four Corners coal contract was renegotiated with the coal supplier, resulting in reduced coal prices for the remaining term of the agreement. The Four Corners coal contract expires in mid-2016. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plant’s operational requirements through mid-2016.

Purchased Power

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 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 solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. (See "Regulation - New Mexico Regulatory Matters.") The Company has a 25-year purchase power agreement with NextEra Energy Resource 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 for two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which commercial operation is estimated to begin in 2012. The Company entered into these contracts to help meet its renewable portfolio requirements.

Other purchases of shorter duration were made during 2011 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,
	2011			2010			2009
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	234,086		$	217,615		$	195,798
Commercial and industrial, small	196,093			188,390			175,328
Commercial and industrial, large	45,407			43,844			34,804
Sales to public authorities	94,370			86,460			77,370
Total retail base revenues	569,956			536,309			483,300
Wholesale:
Sales for resale	2,122			1,943			2,037
Total non-fuel base revenues	572,078			538,252			485,337
Fuel revenues:
Recovered from customers during the period	145,130			170,588			196,081
Under (over) collection of fuel	13,917			(35,408		)	(66,608		)
New Mexico fuel in base rates	73,454			71,876			69,026
Total fuel revenues	232,501			207,056			198,499
Off-system sales:
Fuel cost	74,736			93,516			101,665
Shared margins	3,883			6,114			3,596
Retained margins	(560		)	5,687			10,803
Total off-system sales	78,059			105,317			116,064
Other	35,375			26,626			28,096
Total operating revenues	$	918,013		$	877,251		$	827,996
Number of customers (end of year):
Residential	337,659			334,729			328,553
Commercial and industrial, small	37,942			37,202			36,306
Commercial and industrial, large	49			50			48
Other	4,596			4,841			4,964
Total	380,246			376,822			369,871
Average annual kWh use per residential customer	7,832			7,560			7,244
Energy supplied, net, kWh (in thousands):
Generated	8,936,776			8,465,659			7,979,290
Purchased and interchanged	2,112,596			2,420,869			2,745,500
Total	11,049,372			10,886,528			10,724,790
Energy sales, kWh (in thousands):
Retail:
Residential	2,633,390			2,508,834			2,361,650
Commercial and industrial, small	2,352,218			2,295,537			2,251,399
Commercial and industrial, large	1,096,040			1,087,413			1,024,186
Sales to public authorities	1,579,565			1,542,389			1,482,448
Total retail	7,661,213			7,434,173			7,119,683
Wholesale:
Sales for resale	62,656			53,637			56,931
Off-system sales	2,687,631			2,822,732			2,995,984
Total wholesale	2,750,287			2,876,369			3,052,915
Total energy sales	10,411,500			10,310,542			10,172,598
Losses and Company use	637,872			575,986			552,192
Total	11,049,372			10,886,528			10,724,790
Native system:
Peak load, kW	1,711,000			1,616,000			1,571,000
Net dependable generating capability for peak, kW (1)	1,785,000			1,643,000			1,643,000
Total system:
Peak load, kW (2)	1,965,000			1,889,000			1,723,000
Net dependable generating capability for peak, kW (1) (3)	1,785,000			1,643,000			1,643,000

 _____________________

11

(1) 2011 includes a 138,000 kW increase in net generating capability at Newman related to the completion of the second phase of the Newman Unit 5 construction which consists of two heat recovery steam generators and a steam turbine.

(2) Includes spot sales and net losses of 254,000 kW, 273,000 kW and 152,000 kW for 2011, 2010 and 2009, respectively.

(3) Excludes spot firm purchases, as well as 65,000 kW, 100,000 kW and 233,000 kW for 2011, 2010 and 2009, respectively, of long-term firm on-peak purchases.

12

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 transactions and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The filing included a base rate increase which was based upon an adjusted test year ended June 30, 2009.

On July 30, 2010, the PUCT approved a settlement in the 2009 Texas retail rate case in PUCT Docket No. 37690. The settlement called for an annual non-fuel base rate increase of $17.15 million effective for usage beginning July 1, 2010. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. This increase was partially offset by the provision that, consistent with a prior rate agreement, effective July 1, 2010, the Company shares 90% of off-system sales margins with customers and retains 10% of such margins. Previously, the Company retained 75% of off-system sales margins. All additions to electric plant in service since June 30, 1993 through June 30, 2009 were deemed to be reasonable and necessary with the exception of one small addition. The Company's new customer information system completed in April 2010 was also included in base rates with a 10-year amortization. The settlement provided for the reconciliation of fuel costs incurred through June 30, 2009 except for the recovery of final Four Corners' coal mine reclamation costs. The fuel reconciliation (Docket No. 38361, discussed below) was bifurcated from the rate case to allow for litigation of the final coal mine reclamation costs. The PUCT also approved the use of a formula-based fuel factor which provides for more timely recovery of fuel costs. The PUCT approved a $19.7 million or 11% reduction in the Company's fixed fuel factor as the initial rate under the approved fuel factor formula. The PUCT also approved an energy efficiency cost-recovery factor that includes the recovery of deferred energy efficiency costs over a three-year period.

2012 Texas Retail Rate Case. The Company filed a request with the PUCT (Docket No. 40094), the City of El Paso, and other Texas cities on February 1, 2012 for a $26.3 million increase in rates charged to customers in Texas. The rate filing was made in response to a resolution adopted by the El Paso City Council requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The City has until August 4, 2012 to make a determination regarding the Company's base rates in the City of El Paso. The rate filing used a historical test year ended September 30, 2011, adjusted for known and measurable items, and a return on equity of 10.6%. The filing at the PUCT also includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On November 15, 2011, the El Paso City Council adopted a resolution which established current rates as temporary rates for the Company's customers residing within the city limits of El Paso. Temporary rates will be effective from November 15, 2011 until a final determination is made by the PUCT on the Company's rates in the rate proceeding initiated by the City's Show Cause Order. Upon a final determination by the PUCT, the PUCT may order a refund to customers of money collected in excess of the rate finally ordered, including interest, or shall authorize the Company to surcharge bills to recover the amount, including interest, by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered. The rates proposed by the Company in the Texas rate case included increases for some customer classes and decreases for other customer classes. As a result, consistent implementation of the proposed rates may require the PUCT to reflect the differences in temporary and final rates from November 15, 2011 for each affected class.

While cities in Texas have jurisdiction over rates in their city limits, the PUCT has appellate authority over city rate decisions on a “de novo” basis; therefore, the ultimate authority to set the Company's Texas electric rates is vested in the PUCT. The Company cannot predict the outcome of this proceeding. If the rate case results in implementing lower rates, the resulting lower rates would have a negative impact on the Company's revenues, net income and cash from operations.

Fuel Reconciliation Case (Severed from 2009 Rate Case). Pursuant to the stipulation in the Company's 2009 rate case, the PUCT established Docket No. 38361 to address the one fuel reconciliation issue not settled by the parties. That single issue was a determination of the proper amount of the Four Corners' coal mine final reclamation costs to be recovered from the Company's Texas retail customers. The hearing on the merits of the case was held on August 11, 2010. On November 23, 2010 the Administrative Law Judge (the “ALJ”) issued the Proposal for Decision which approved the Company's request. The PUCT issued a final order approving the Proposal for Decision on January 27, 2011.

13

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. The Company received approval on July 30, 2010 in PUCT Docket No. 37690 (discussed above), 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.

The Company has filed the following petitions 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 dates the Company filed the petitions and the dates a final order was issued by the PUCT approving the refunds to customers. The fuel cost over-recovery periods represent the months in which the over-recoveries took place and the refund periods represent the billing month(s) in which customers received the refund amounts shown, including interest:

Docket No.	Date Filed	Date Approved	Recovery Period	Refund Period	Refund Amount (In thousands)
37788	December 17, 2009	February 11, 2010	September – November 2009	February 2010	$	11,800
38253	May 12, 2010	July 15, 2010	December 2009 – March 2010	July – August 2010	11,100
38802	October 20, 2010	December 16, 2010	April – September 2010	December 2010	12,800
39159	February 18, 2011	May 3, 2011	October – December 2010	April 2011	11,800

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

Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor		Effective Billing Month
38895	November 23, 2010	January 6, 2011	(14.7	)%	January 2011
39599	July 15, 2011	August 30, 2011	9.4	%	August 2011

As noted above, the rate filing filed with the PUCT on February 1, 2012 (Docket No. 40094), includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. However, this filing does not request a change in the fixed fuel factor.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2012. On May 2, 2011, the Company filed with the PUCT an application for approval to revise its energy efficiency cost recovery factor (“EECRF”), which was assigned PUCT Docket No. 39376. A unanimous settlement resolving all issues was filed with the PUCT on July 15, 2011. The settlement allows the Company to recover $8.3 million and supports the Company's request to revise its demand and energy goals and EECRF cost caps as well as the Company's request to increase its 2012 EECRF, effective beginning with the first billing cycle of its January 2012 billing month. A final order in the case was issued August 23, 2011, approving the settlement.

Petition for Approval to Revise Military Base Discount Recovery Factor. On July 14, 2011, the Company filed with the PUCT a petition requesting approval to revise its Military Base Discount Recovery Factor (“MBDRF”) tariff to account for under-recovery of discount charges during 2010 and for 2011 discounts. A final order was issued January 12, 2012 revising the MBDRF to 0.936% and allowing $3.9 million dollars of under-recovered discount charges to begin February 1, 2012.

14

Application for a Certificate of Convenience and Necessity (“CCN”) for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned PUCT Docket No. 38717. A unanimous settlement to approve the CCN was filed on March 2, 2011, and a final order granting the CCN was approved on April 8, 2011.

Project to Investigate Early February 2011 Outages and Curtailments. On February 8, 2011, the PUCT opened Project No. 39134, Investigation into Power Outages in El Paso Electric's Service Territory. In this project, the PUCT is investigating the Company's power plant outages and customer curtailments that occurred February 2-4, 2011, as a result of the extreme cold weather in the El Paso area. The PUCT Staff conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event. On May 13, 2011, the PUCT Staff issued a report stating that, as of then, it had not identified violations by the Company of the Texas electric utility regulatory statute or PUCT rules. The report also stated that the PUCT Staff would continue to monitor the extreme cold weather event results and subsequent forthcoming information as the Company and other regulatory agencies complete their ongoing investigations.

On February 15, 2011, the City Council of El Paso passed a motion that, upon the conclusion of other hearings and investigations into the extreme cold weather event, the Mayor would call for Special City Council meetings or public hearings to evaluate how the three utility companies operating within the city, including the Company, performed during the extreme weather event. The El Paso City Council retained a consultant to assess the Company's activities during the weather event and the Company's subsequent actions to prevent outages during a similar future event. The El Paso City Council's consultant presented the following three recommendations to the El Paso City Council on December 20, 2011: (i) request the Company to prepare and present an updated reliability study; (ii) request the Company and El Paso Water Utilities to present their coordinated plans for power and water supply to critical loads during severe weather events; and (iii) request the Company to file an updated emergency operations plan with both the PUCT and the El Paso City Council which will be completed in 2012. The El Paso City Council unanimously passed a motion to approve the three recommendations. At the January 10, 2012 El Paso City Council Meeting, the Company presented information requested in recommendations (i) and (ii) above.

Application of El Paso Electric Company to Amend its Certificate of Convenience and Necessity for Five Solar Power Generation Projects. On December 9, 2011, the Company filed a petition seeking a CCN to construct five solar powered generation projects, totaling approximately 2.6 MW, at four locations within the City of El Paso and one location in the Town of Van Horn. This case was assigned PUCT Docket No. 39973 and is still pending.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On May 29, 2009, the Company filed a general rate case using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT. A comprehensive unopposed stipulation (the “2009 New Mexico Stipulation”) was reached in this general rate case and filed on October 8, 2009. The 2009 New Mexico Stipulation provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and a revision of depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company's Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) without conditions or variance. In addition, it modified the market pricing of capacity and energy provided by Palo Verde Unit 3 using a methodology based upon a previous purchased power contract with Credit Suisse Energy, LLC. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation, and the stipulated rates went into effect with January 2010 bills.

Application for Approval to Recover Regulatory Disincentives and Incentives. On August 31, 2010, the Company filed an application for approval of its proposed rate design methodology to recover regulatory disincentives and incentives associated with the Company's energy efficiency and load management programs in New Mexico. On March 18, 2011, the Company entered into an uncontested stipulation which would provide for a rate per kWh of energy efficiency savings that would be recovered through the efficient use of energy rider. A hearing on the uncontested stipulation was held on April 26, 2011 and briefs were filed on September 26, 2011. A final order was issued on November 22, 2011 in which the NMPRC did not adopt the unopposed stipulation, but modified the structure of the energy rider to reduce the return to two percent and made the mechanism temporary.  The Company filed a Notice of Appeal with the Supreme Court of the State of New Mexico on January 20, 2012 on the grounds that the NMPRC's decision is arbitrary and without substantial evidence.

Application for a CCN for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the

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City of Sunland Park in southeast New Mexico. This case was assigned NMPRC Case No. 10-00301-UT. On April 13, 2011 an unopposed stipulation was filed in this case seeking approval of a CCN for the Company to construct, own and operate the 87 MW generating unit. A final order on this case approving the CCN was issued on June 23, 2011.

Application for Approval of 2011 New and Modified Energy Efficiency Programs. On February 15, 2011, the Company filed its Application for Approval of New and Modified Energy Efficiency Programs for 2011 with the NMPRC. On June 22, 2011, parties to this case entered into a partial stipulation, agreeing on all issues, except for a military base free-ridership issue. On June 24, 2011, the New Mexico Attorney General filed a statement in opposition to the proposed partial stipulation. On January 25, 2012, a hearing examiner issued a recommended decision modifying the stipulation by approving the Energy Efficiency programs and budgets with the exception of the Commercial Lighting Program, approving the adder for 2011 but not for 2012 or 2013 and excluding the Military Research & Development Class from participation in the rate rider and reducing the Company's required saving goals accordingly. On February 2, 2012, the Company filed certain exceptions to the recommended decision and requested an interim order related to this matter.

2011 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2011, the Company filed its Application for Approval of its 2011 Renewable Procurement Plan with the NMPRC, which was assigned NMPRC Case No. 11-00263-UT. The filing identified renewable resources intended to meet the Company's Renewable Portfolio Standard (“RPS”) requirements in 2012 and 2013. The renewable resources in the 2011 Renewable Procurement Plan which were previously approved by the NMPRC, will allow the Company to meet the full RPS requirement of 10% of the Company's jurisdictional retail energy sales for 2012 and 2013. The Company's 2011 Renewable Procurement Plan also addresses the diversity targets in 2012 and 2013 required by NMPRC Rule 572 and demonstrates that the Company will meet those targets. The 2011 Renewable Procurement Plan also demonstrates that the Company will meet its solar diversity target in 2012 and comply with the terms of a previously-approved variance for 2011. A hearing in this case was held on October 13, 2011. A final order was issued on December 15, 2011 approving the 2011 Renewable Procurement Plan.

Investigation into Rates for Church Customers. On July 12, 2011, the NMPRC initiated an investigation into the rates the Company charges its church customers which were approved in Case No. 09-00171-UT. The investigation, Case No. 11-00276-UT, was ordered to determine whether the Company's rates to its church customers are unjust and unreasonable and should be revised. The Company filed a response on August 1, 2011. A mediation conference was held on August 23, 2011 which resulted in an Unopposed Joint Stipulation, filed on October 14, 2011. The stipulation limits billing impacts to religious organizations that take service under the Company's standard small commercial rate. The stipulation was approved by the NMPRC on October 27, 2011.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the NMPRC in Case No. 11-00349-UT to amend and restate the Company's $200 million revolving credit facility ("RCF"), which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and Rio Grande Resources Trust ("RGRT") amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million during the term of the RCF, subject to lender's approval. All other terms remain substantially the same.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company's transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in Arizona. The Company asserted that TEP's rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Company's favor, finding that TEP does not have transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP's request for a rehearing of the FERC's decision was granted in part and denied in part in an order issued October 4, 2006, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative

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law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.

On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time.

The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for service relating to the LEF. On December 3, 2008, the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company

also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC's decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company's transmission system on a going forward basis. On July 7, 2010, the FERC denied the Company's request for rehearing. On July 23, 2010, the Company filed a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) and on August 18, 2010, TEP filed a motion to intervene in the proceeding. On January 14, 2011, the Company and TEP filed a joint consent motion, asking the Court to hold the proceedings in abeyance while the parties engaged in settlement discussions. The Court granted the motion on January 19, 2011.

On August 31, 2011, the FERC issued an order approving a settlement between TEP and the Company that became effective November 1, 2011. The settlement reduces TEP's transmission rights under the Transmission Agreement from 200 MW to 170 MW, and TEP and the Company have entered into two new firm transmission capacity agreements at applicable tariff rates for a total of 40 MW. Those two new service agreements were entered into and became effective November 1, 2011. Also under the terms of the settlement, TEP made a lump-sum cash payment to the Company of approximately $5.4 million for the period February 1, 2006 through September 30, 2011, including interest income. This adjustment was recorded in the three months ended September 30, 2011. The Company shared with its customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries. As part of the settlement, the Company withdrew its appeal before the Court of Appeals.

In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. As part of the settlement, this lawsuit was dismissed.

With the implementation of the settlement effective November 1, 2011, these matters between the Company and TEP were fully resolved.

Inquiry into Early February 2011 Outages and Curtailments. On February 14, 2011, the FERC directed its staff to initiate an inquiry into power plant outages and customer curtailments by power generators and gas suppliers in the Southwestern United States, including the Company, in early February 2011, as a result of the extreme cold weather. The FERC specifically stated that its inquiry is not an enforcement investigation. On August 16, 2011, the FERC released its staff report, Docket No. AD11-9-000, where it made recommendations to help prevent a recurrence of such outages in the future, and making no finding of violations or assessments of penalties.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the FERC in Docket No. ES11-43-000 to amend and restate the Company's $200 million RCF, which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and Rio Grande Resources Trust ("RGRT") amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million,

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subject to lender's approval. All other terms remain substantially the same. See "Energy Sources - Nuclear Fuel - Nuclear Fuel Financing."

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

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

Nuclear Regulatory Commission ("NRC"). The NRC has jurisdiction over the Company's licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.

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 2012.

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 also provides 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 agreements 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

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 bases represent approximately 5% of annual retail revenues. The Company entered into 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 for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term expiring in January 2016.

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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 2009 Texas rate case, PUCT Docket No. 37690, established the Company's current retail base rates in Texas, effective July 1, 2010. 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. On February 1, 2012, we filed a request with the PUCT (Docket No. 40094), the City of El Paso and other Texas cities, for a $26.3 million increase in rates charged to customers in Texas. The rate filing was made in response to a resolution adopted by the El Paso City Council requiring us to show cause why our base rates for customers in El Paso should not be reduced.

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

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

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. 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 2011, we refinanced and extended our revolving credit facility which could help fund the construction of this 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 this unit is 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 this unit.

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, recent stock market performance has provided returns that are below historic average for 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, the continued volatile economy may result in reduced customer demand, both in the retail and wholesale markets, and increases

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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 35% of our available net generating capacity and provided approximately 45% of our energy requirements for the twelve months ended December 31, 2011. 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 90.7% and 90.4% in the twelve months ended December 31, 2011 and 2010, 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 power contract with Credit Suisse Energy, LLC. Fuel and purchased power expenses in New Mexico and Texas are subject to reconciliation by the PUCT and the 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 current rate filing at the PUCT (Docket No. 40094) includes a request to reconcile $356.6 million of fuel expense for the period July 1, 2009 through September 30, 2011. 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, 2011 and 2010, the Company had a net under-collection balance of $7.0 million and a net over-collection balance of $19.0 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

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(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, 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.

Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Consolidated Financial Results

We are 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.  

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 Utility MACT. If these regulations survive legal and Congressional challenges, the cost to us to comply could adversely affect our operations and consolidated financial results.

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

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

The Company emits GHGs 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. In 2012, EPA plans to publish draft rules to regulate GHG from new or modified power plants. Further, state regulation may precede federal GHG legislation. In the State of New Mexico, where we operate one facility and have an interest in another facility, the New Mexico Environmental Improvement Board approved two separate rulemakings in November and December 2010 to limit GHG emissions. To date, one of these rulemakings has been repealed by the New Mexico Environmental Improvement Board. There are various uncertainties relating to the remaining regulation, including whether current legal challenges to it will be successful, but as drafted, we do not expect this regulation to result in significant costs to us.

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.

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Item 1B. Unresolved Staff Comments

None.

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 24, 2012, were as follows:

Name	Age	Current Position and Business Experience
Thomas V. Shockley III	66	Interim Chief Executive Officer since January 2012; Vice – Chairman and Chief Operating Officer for American Electric Power from June 2000 to August 2004; retired in 2004.
David W. Stevens *	52	Chief Executive Officer since November 2008; Principal of Professional Consulting Services, LLC from December 2007 to November 2008; President, Chief Executive Officer and Board Member for Cascade Natural Gas Corporation from April 2005 to July 2007.
David G. Carpenter	56	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.
Richard G. Fleager	61	Senior Vice President – Customer Care and External Affairs since April 2009; Vice President for Texas Gas Service from September 1997 to March 2009.
Mary E. Kipp	44	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	58	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	55	Senior Vice President – Operations since May 2011; Vice President – Transmission and Distribution from May 2006 to May 2011.
Steven T. Buraczyk	44	Vice President – System Operations and Planning since January 2011; Vice President – Power Marketing and Fuels from July 2008 to January 2011; Director of Power Marketing and Fuels from August 2006 to July 2008.
Steven P. Busser	43	Vice President – Treasurer since January 2011; Vice President – Treasurer and Chief Risk Officer from May 2006 to January 2011.
Robert C. Doyle	52	Vice President – Transmission and Distribution since June 2011; Vice President – New Mexico Affairs from February 2007 to June 2011; Director – New Mexico Affairs from January 2007 to February 2007.
Nathan T. Hirschi	48	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.
Kerry B. Lore	52	Vice President – Customer Care since December 2008; Vice President – Administration from May 2003 to December 2008.
Andres R. Ramirez	51	Vice President – Power Generation since February 2006.
Guillermo Silva, Jr.	58	Corporate Secretary since February 2006.
John A. Whitacre	62	Vice President – Power Marketing and Fuels since January 2011; Vice President – System Operations and Planning from May 2006 to January 2011.

__________________

* On January 30, 2012, Mr. Stevens resigned from his position as Chief Executive Officer of the Company, effective March 2, 2012, and as a Director immediately. The Board of Directors appointed Mr. Shockley to serve as interim Chief Executive Officer initially during a transition period until Mr. Stevens' departure and thereafter while a search is conducted to replace Mr. Stevens.

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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. Removed and Reserved

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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)
2010
First Quarter	$	20.98	$	18.74	$	20.60	$	—
Second Quarter	22.15		18.76		19.35		—
Third Quarter	23.82		18.81		23.78		—
Fourth Quarter	28.65		23.51		27.53		—
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

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Performance Graph

The following graph compares the performance of the Company’s Common Stock to the performance of the NYSE Composite, and the Edison Electric Institute’s Index of investor-owned electric utilities setting the value of each at December 31, 2006 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return as compared to the NYSE, and the EEI, as reflected in the graph.

	12/31/2006	12/31/2007	12/31/2008	12/31/2009	12/31/2010	12/31/2011
EE	100	105	74	83	113	142
EEI	100	117	86	96	102	123
NYSE US	100	107	63	79	87	82

As of January 31, 2012, there were 3,335 holders of record of the Company’s common stock. The Company has been paying quarterly dividends on its common stock since June 30, 2011 and paid a total of $27.2 million in cash dividends during the twelve months ended December 31, 2011. On January 26, 2012, our Board of Directors declared a quarterly cash dividend of $0.22 per share payable on March 30, 2012 to shareholders of record on March 15, 2012. At the current payout rate, we would expect to pay total cash dividends of approximately $35.2 million during 2012. The Board of Directors plans to review the Company's dividend policy annually, in conjunction with the annual shareholders meeting held in the second quarter of each year. Our current expectation is that our payout ratio will trend upward from its current level, with a payout ratio of approximately 45% being the anticipated target for 2012. Since 1999, the Company has 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”). During the twelve months ended December 31, 2011, the Company repurchased 2,782,455 shares of common stock in the open market at an aggregate cost of $86.5 million under both a previously authorized program and under the 2011 Plan. As of December 31, 2011, 393,816 shares remain eligible for repurchase under the 2011 Plan. During the fourth quarter of 2011, the Company repurchased 280,389 shares at an aggregate cost of $9.2 million. The table below provides the amount of the fourth quarter repurchases on a monthly basis.

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Period	Total Number of Shares Purchased	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be  Purchased Under the Plans or Programs
October 1 to October 31, 2011	—	$	—	—	674,205
November 1 to November 30, 2011	162,435	32.86		162,435	511,770
December 1 to December 31, 2011	117,954	33.03		117,954	393,816

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,
	2011		2010		2009		2008		2007
Operating revenues	$	918,013	$	877,251	$	827,996	$	1,038,930	$	877,427
Operating income	$	190,803	$	168,962	$	133,165	$	145,736	$	128,321
Income before extraordinary items	$	103,539	$	90,317	$	66,933	$	77,621	$	74,753
Extraordinary gain, net of tax (a)	$	—	$	10,286	$	—	$	—	$	—
Net income	$	103,539	$	100,603	$	66,933	$	77,621	$	74,753
Basic earnings per share:
Income before extraordinary items	$	2.49	$	2.08	$	1.50	$	1.73	$	1.64
Extraordinary gain (a)	$	—	$	0.24	$	—	$	—	$	—
Net income	$	2.49	$	2.32	$	1.50	$	1.73	$	1.64
Weighted average number of shares outstanding	41,349,883		43,129,735		44,524,146		44,777,765		45,563,858
Diluted earnings per share:
Income before extraordinary items	$	2.48	$	2.07	$	1.50	$	1.72	$	1.63
Extraordinary gain (a)	$	—	$	0.24	$	—	$	—	$	—
Net income	$	2.48	$	2.31	$	1.50	$	1.72	$	1.63
Weighted average number of shares and dilutive
potential shares outstanding	41,587,059		43,294,419		44,595,067		44,930,109		45,873,018
Dividends declared per share of common stock	$	0.66	$	—	$	—	$	—	$	—
Cash additions to utility property, plant and equipment	$	178,041	$	169,966	$	209,974	$	198,711	$	144,588
Total assets	$	2,396,851	$	2,364,766	$	2,226,152	$	2,069,083	$	1,853,888
Long-term debt and financing obligations, net of
current portion	$	816,497	$	849,745	$	804,975	$	809,718	$	655,111
Common stock equity	$	760,251	$	810,375	$	722,729	$	694,229	$	666,459

 ______________________

(a) Extraordinary gain for 2010 includes 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, 2011, we had recorded regulatory assets currently subject to recovery in future rates of approximately $101.0 million and regulatory liabilities of approximately $21.0 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

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

Overview

The following is an overview of our results of operations for the years ended December 31, 2011, 2010 and 2009. Income before extraordinary item for the years ended December 31, 2011, 2010 and 2009 is shown below:

	Years Ended December 31,
	2011		2010		2009
Income before extraordinary item (in thousands)	$	103,539	$	90,317	$	66,933
Basic earnings per share before extraordinary item	2.49		2.08		1.50

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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 2011 and 2010, 2010 and 2009, and 2009 and 2008 (in thousands):

	2011				2010				2009
Prior year December 31 income before extraordinary item	$	90,317			$	66,933			$	77,621
Change in (net of tax):
Increased retail non-fuel base revenues	21,198			(a)	33,395			(b)	8,292			(c)
Elimination of Medicare Part D tax benefit	4,787			(d)	(4,787		)	(d)	—
Increased transmission wheeling revenue	3,197			(e)	1,446				1,887
Decreased (increased) Palo Verde operations and maintenance expense	640				2,753			(f)	(2,266		)	(g)
Decreased (increased) operations and maintenance at fossil fuel generating plants	(3,725		)	(h)	(1,120		)		517
Increased (decreased) off-system sales margins retained	(3,935		)	(i)	(3,224		)	(j)	(7,140		)	(k)
Decreased (increased) customer care expense	(2,069		)	(l)	(2,445		)	(m)	(483		)
Increased interest on long-term debt (net of capitalized interest)	(377		)		775				(3,518		)	(n)
Increased (decreased) AFUDC	(3,804		)	(o)	1,909			(p)	2,327			(p)
Decreased (increased) transmission and distribution operations and maintenance expense	(1,964		)	(q)	1,200				378
Decreased (increased) administrative and general expense	(1,342		)		(3,502		)	(r)	(2,544		)	(s)
Increased taxes other than income taxes	(678		)		(2,830		)	(t)	(121		)
Increased (decreased) deregulated Palo Verde Unit 3 revenues	(808		)		1,235				(7,121		)	(u)
Decreased (increased) depreciation and amortization	(202		)		(3,821		)	(v)	393
Other	2,304				2,400				(1,289		)
Current year December 31 income before extraordinary item	$	103,539			$	90,317			$	66,933

______________________ 

(a) 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 and1.4% growth in the average number of retail customers served in 2011. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates.

(b) 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.

(c) Retail non-fuel base revenues increased in 2009 compared to 2008 primarily due to increased kWh sales to residential customers and public authorities partially offset by a decrease in kWh sales to large commercial and industrial customers.

(d) 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.

(e) 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.

(f) 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.

(g) Palo Verde non-fuel operations and maintenance expense increased for 2009 compared to 2008 due to increased employee benefit expense and increased operating costs, partially offset by decreased maintenance costs in 2009.

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

(i) 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.

(j) 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.

(k) Lower retained margins on off-system sales in 2009 compared to 2008 are primarily the result of reduced margins per MWh due to lower market prices and a decline in MWh sales.

(l) 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.

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(m) 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.    

(n) Interest expense on long-term debt increased for 2009 compared to 2008 due to the issuance of $150 million of 7.5% Senior Notes in June 2008 and higher interest rates on auction rate pollution control bonds in 2008.

(o) AFUDC (allowance for funds used during construction) decreased in 2011 compared to 2010 primarily due to lower balances of construction work in progress subject to AFUDC.

(p) AFUDC increased primarily due to higher balances of construction work in progress subject to AFUDC.

(q) 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.

(r) Administrative and general expenses increased in 2010 compare to 2009 primarily due to increased pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our pension plan.

(s) Administrative and general expenses increased in 2009 compared to 2008 primarily due to increased accruals for employee incentive compensation and increased pension and benefits expenses reflecting a lower discount rate used to determine postretirement benefit costs.

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

(u) Deregulated Palo Verde Unit 3 revenues in 2009 reflect lower proxy market prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in April and May 2009.

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

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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. 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 shared 25% of off-system sales margins with our Texas and New Mexico customers and retained 75% of off-system sales margins through June 30, 2010. Pursuant to rate agreements in prior years, effective July 1, 2010, we share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. We are sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract which was effective April 1, 2008.

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,
	2011		2010		2009
Residential	41	%	41	%	41	%
Commercial and industrial, small	34		35		36
Commercial and industrial, large	8		8		7
Sales to public authorities	17		16		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 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,
	2011		2010		2009
January 1 to March 31	18	%	21	%	21	%
April 1 to June 30	27		24		26
July 1 to September 30	34		33		30
October 1 to December 31	21		22		23
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 30-year average for 2011, 2010 and 2009.

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	2011	2010	2009	30-year Average
Heating degree days	2,402	2,273	2,144	2,426
Cooling degree days	3,135	2,738	2,768	2,410

Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.4% in 2011 and 1.7% in 2010. See the tables presented on pages 35 and 36 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. The rate structure in New Mexico, effective January 1, 2010, and in Texas, effective July 1, 2010, results in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. As a result, our revenues are more seasonal than prior to July 2010.

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 30% above the 30-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 last year. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates.

Retail non-fuel base revenues increased by $53.0 million or 11.0% for the twelve months ended December 31, 2010 when compared to the same period in 2009. The increase was primarily due to the non-fuel base rates implemented in 2010 in New Mexico and Texas and a 4.4% increase in retail kWh sales driven by improving local economic conditions. KWh sales to residential customers increased 6.2% reflecting a 1.8% growth in the average number of customers served and colder winter weather in the first quarter of 2010. During the twelve months ended December 31, 2010, heating degree days were 6% above the same period in 2009. KWh sales to small commercial and industrial customers increased 2.0% reflecting a 1.4% increase in the average number of small commercial and industrial customers served. Retail non-fuel base revenues also increased due to a 26% increase in non-fuel base revenues from large commercial and industrial customers attributable to increased kWh sales to large commercial and industrial customers of 6.2% and the implementation of higher rates in new contracts and tariff rates with several large customers whose contracts had expired. KWh sales to public authorities increased 4.0% largely due to increased sales to military bases.

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

We under-recovered fuel costs by $13.9 million in the twelve months ended December 31, 2011. In the twelve months ended December 31, 2010 and 2009, we over-recovered fuel costs by $35.4 million and $66.6 million, respectively. Refunds of $12.0 million and $34.8 million were returned to our Texas customers in the twelve months ended December 31, 2011 and 2010, respectively. Refunds net of surcharges of $0.5 million were returned to our Texas customers in the twelve months ended December 31, 2009. At December 31, 2011, we had a fuel under-recovery balance of $7.0 million, including an under-recovery balance of $9.1 million in Texas partially offset by an over-recovery balance of $2.1 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2012.

Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. 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. 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. Effective July 1, 2010, we share 90% of off-system sales margins with customers and retain 10% of 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, 2011, 2010 and 2009 (in thousands except for MWhs).

	Twelve Months Ended December 31,
	2011			2010		2009
MWh sales	2,687,631			2,822,732		2,995,984
Sales revenues	$	78,059		$	105,317	$	116,064
Fuel cost	$	74,736		$	93,516	$	101,665
Total margins	$	3,323		$	11,801	$	14,399
Retained margins	$	(560	)	$	5,687	$	10,803

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 by power purchases required for system reliability during extremely cold weather in February 2011. Off-system sales revenues decreased $10.7 million or 9.3% for the twelve months ended December 31, 2010 when compared to 2009 as a result of lower average market prices for power and a 5.8% decline in MWh sales. For the twelve months ended December 31, 2010, retained margins decreased $5.1 million or 47.4% when compared to the same period in 2009. Customers were credited with 25% of the off-system sales margins through fuel recovery mechanisms through June 30, 2010. In July 2010, off-system sales margins shared with customers in Texas and New Mexico increased to 90%.

34

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

							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, 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:	2010			2009			Amount			Percent
kWh sales:
Retail:
Residential	2,508,834			2,361,650			147,184			6.2	%
Commercial and industrial, small	2,295,537			2,251,399			44,138			2.0
Commercial and industrial, large	1,087,413			1,024,186			63,227			6.2
Sales to public authorities	1,542,389			1,482,448			59,941			4.0
Total retail sales	7,434,173			7,119,683			314,490			4.4
Wholesale:
Sales for resale	53,637			56,931			(3,294		)	(5.8	)
Off-system sales	2,822,732			2,995,984			(173,252		)	(5.8	)
Total wholesale sales	2,876,369			3,052,915			(176,546		)	(5.8	)
Total kWh sales	10,310,542			10,172,598			137,944			1.4
Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	217,615		$	195,798		$	21,817		11.1	%
Commercial and industrial, small	188,390			175,328			13,062			7.5
Commercial and industrial, large	43,844			34,804			9,040			26.0
Sales to public authorities	86,460			77,370			9,090			11.7
Total retail non-fuel base revenues	536,309			483,300			53,009			11.0
Wholesale:
Sales for resale	1,943			2,037			(94		)	(4.6	)
Total non-fuel base revenues	538,252			485,337			52,915			10.9
Fuel revenues:
Recovered from customers during the period	170,588			196,081			(25,493		)	(13.0	)	(1)
Under (over) collection of fuel	(35,408		)	(66,608		)	31,200			(46.8	)
New Mexico fuel in base rates	71,876			69,026			2,850			4.1
Total fuel revenues	207,056			198,499			8,557			4.3		(2)
Off-system sales:
Fuel cost	93,516			101,665			(8,149		)	(8.0	)
Shared margins	6,114			3,596			2,518			70.0
Retained margins	5,687			10,803			(5,116		)	(47.4	)
Total off-system sales	105,317			116,064			(10,747		)	(9.3	)
Other	26,626			28,096			(1,470		)	(5.2	)	(3)
Total operating revenues	$	877,251		$	827,996		$	49,255		5.9
Average number of retail customers:
Residential	331,869			326,002			5,867			1.8
Commercial and industrial, small	36,536			36,040			496			1.4
Commercial and industrial, large	49			49			—			—
Sales to public authorities	4,701			4,940			(239		)	(4.8	)
Total	373,155			367,031			6,124			1.7

 _______________________

(1) Excludes $34.8 million refunds in 2010 and refunds net of surcharges of $0.5 million in 2009 related to prior periods' Texas deferred fuel revenues.

(2) Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $16.1 million and $14.1 million, respectively. 

(3) Represents revenues with no related kWh sales.

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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 35% of our available net generating capacity and approximately 55% of our Company-generated energy for the twelve months ended December 31, 2011. 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.

Average costs per MWh were flat while energy expenses increased $6.9 million or 2.4% for the twelve months ended December 31, 2011 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 13% decrease in MWhs purchased and a 6% decrease in the average price of purchased power. Total energy requirements increased 0.2 million MWhs in 2011 compared to 2010 due to increased retail sales.

Energy expenses decreased $2.7 million or 1% for the twelve months ended December 31, 2010 compared to 2009, primarily due to decreased costs of purchased power of $16.7 million resulting from a 12% decrease in MWhs purchased and a 4% decrease in the average price of power purchased. This decrease was partially offset by: (i) an increase of $9.6 million in natural gas costs due to a 21% increase in MWhs generated with natural gas partially offset by a 12% decrease in the average price of natural gas, and (ii) an increase of $6.2 million in the cost of nuclear fuel due to a 33% increase in the cost of nuclear fuel consumed partially offset by a $3.3 million DOE settlement related to spent nuclear fuel. Total energy requirements increased 0.2 million MWhs in 2010 compared to 2009 due to increased retail sales.

The table below details the sources and costs of energy for 2011, 2010 and 2009.

	2011						2010
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	164,260	(a)	3,346,789	$	50.02	$	153,568		2,890,110	$	53.14
Coal	15,273		(b)	647,932	19.97		11,011			650,236	17.79
Nuclear	43,974			4,942,055	8.90		35,250		(c)	4,925,313	7.82
Total	223,507			8,936,776	25.10		199,829			8,465,659	24.06
Purchased power	75,149			2,112,596	35.57		91,916			2,420,869	37.97
Total energy	$	298,656		11,049,372	27.10		$	291,745		10,886,528	27.15
	2009
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	143,943		2,385,632	$	60.34
Coal	12,838			744,858	17.24
Nuclear	29,056			4,848,800	5.99
Total	185,837			7,979,290	23.29
Purchased power	108,603			2,745,500	39.56
Total energy	$	294,440		10,724,790	27.45

 _____________________

(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 $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.

Other operations expense increased $8.4 million or 3.9% in 2010 compared to 2009 primarily due to: (i) increased customer care expenses related to the transition to our new customer billing system and increased uncollectible customer accounts of $3.9 million, and (ii) increased administrative and general expense of $5.2 million due to increased pension and benefits expense reflecting changes in actuarial assumptions used to calculate expenses for our pension plans.

Maintenance expense

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.

Maintenance expenses decreased $2.8 million or 4.7% in 2010 compared to 2009 due primarily to decreased maintenance expense at Palo Verde of $3.0 million as a result of decreased maintenance during refueling outages in 2010 compared to refueling outages in 2009.

Depreciation and amortization expense

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. Depreciation and amortization expense increased $6.1 million or 8.1% in 2010 compared to 2009 primarily due to increased depreciable plant balances including the new customer information system, increased amortization of New Mexico rate case costs, and increased depreciation rates.

Taxes other than income taxes

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. Taxes other than income taxes increased $4.5 million or 9.0% in 2010 compared to 2009 primarily due to increased revenue-related taxes and increased property taxes.

Other income (deductions)

Other income (deductions) decreased $2.8 million or 19.4% in 2011 compared to 2010 due to decreased allowance for equity funds used during construction (“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.

Other income (deductions) increased $3.5 million or 33% in 2010 compared to 2009 primarily as a result of: (i) increased AEFUDC of $1.5 million due to higher balances of construction work in progress in 2010, and (ii) increased investment and interest income primarily as a result of $2.2 million in impairment and net realized losses on investments in our Palo Verde decommissioning trusts in 2009 compared to $0.1 million impairment and net realized losses in 2010.

Interest charges (credits)

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

Interest charges (credits) decreased $2.0 million or 4.6% in 2010 compared to 2009 primarily due to: (i) lower interest rates on pollution control bonds and (ii) increased ABFUDC as a result of higher balances of construction work in progress in 2010. Two series of pollution control bonds were refunded in March 2009 at a fixed interest rate of 7.25% which was lower than the variable interest rates applied to these bonds before refunding.

Income tax expense

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

38

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. Income tax expense, before extraordinary item, increased by $18.0 million or 54.4% in 2010 compared to 2009 primarily due to an increase in pre-tax income and a one-time non-cash charge to tax expense related to the PPACA. A 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 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.

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 June 2011, the FASB issued new guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The new guidance requires an entity to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both presentations, an entity would have been required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. Historically, we have used the consecutive two-statement approach; however, this new guidance could require additional disclosure on our statement of operations and related notes. In December 2011, the FASB issued new guidance to defer the effective date for amendments to the presentation of reclassification of items out of accumulated other comprehensive income. Deferring the effective date will allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, we will continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before the guidance issued in June 2011 until further guidance becomes available.

In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include: (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances, and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires: (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. This guidance requires additional disclosure on fair value measurements but did not impact our consolidated financial statements.

Inflation

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

Liquidity and Capital Resources

We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2011, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the revolving credit facility, consisted of 46.3% common stock equity and 53.7% debt. At December 31, 2011, we had on hand $8.2 million in cash and cash equivalents.

39

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, and operating expenses including fuel costs, maintenance costs, dividends and taxes.

Capital Requirements. During the twelve months ended December 31, 2011, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, the repurchase of common stock, 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. Newman Unit 5, a 288 MW gas-fired combined cycle combustion turbine generating unit, was completed in two phases. The first phase of Newman Unit 5 was completed in May 2009, and the second phase was completed in April 2011. In total, we expended $235.2 million on Newman Unit 5, including $25.4 million in 2011. These amounts include AFUDC. Estimated construction expenditures for all capital projects for 2012 are approximately $242 million, and we expect cash from operations to continue to be a primary source of funds for these capital expenditures. See Part I, Item 1, “Business - Construction Program”. Cash capital expenditures for new electric plant were $178.0 million in the twelve months ended December 31, 2011 and $170.0 million in the twelve months ended December 31, 2010.

On December 30, 2011, we paid $8.8 million of quarterly dividends to shareholders. We paid a total of $27.2 million in cash dividends during the twelve months ended December 31, 2011. On January 26, 2012, our Board of Directors declared a quarterly cash dividend of $0.22 per share payable on March 30, 2012 to shareholders of record on March 15, 2012. At the current payout rate, we would expect to pay total cash dividends of approximately $35.2 million during 2012. The Board of Directors plans to review the Company's dividend policy annually, in conjunction with the annual shareholders meeting held in the second quarter of each year. Our current expectation is that our payout ratio will trend upward from its current level, with a payout ratio of approximately 45% being the anticipated target for 2012. In addition, we may repurchase common stock in the future. Since 1999, we have returned cash to stockholders through a stock repurchase program pursuant to which we have bought approximately 25.4 million shares at an aggregate cost of $423.6 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. On March 21, 2011, the Board of Directors authorized repurchases of up to 2.5 million additional shares of the Company's outstanding common stock (“2011 Plan”). During the twelve months ended December 31, 2011, we repurchased 2,782,455 shares of common stock in the open market at an aggregate cost of $86.5 million. As of December 31, 2011, 393,816 shares remain eligible for purchase under the 2011 Plan.

We continue to utilize a combination of dividends and share repurchases to return capital to our shareholders, while maintaining a balanced capital structure. We will also 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 dividend 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, tax payments are expected to be minimal in 2012.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $13.8 million and $8.5 million to our retirement plans during the twelve months ended December 31, 2011 and 2010, respectively. We expect our funding requirements to increase in 2012. We also contributed $2.2 million and $4.6 million to our other postretirement benefit plan during the twelve months ended December 31, 2011 and 2010, respectively. We contributed $8.3 million and $8.2 million to our decommissioning trust funds for 2011 and 2010, 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. During the twelve months ended December 31, 2011, we had increased cash from operations when compared to the same period in 2010, which reflects the increase in net income before a non-cash extraordinary gain in 2010. Cash flows were also impacted by an increase in deferred income taxes and an increase in accounts payable, offset by the timing of collection of fuel revenues to recover actual fuel expenses in 2011 compared to 2010. During the twelve months ended December 31, 2011, the Company had an under-recovery of fuel costs, net of refunds, of $26.0 million as compared to an over-recovery, net of refunds, of $1.0 million during the twelve months ended December 31, 2010. At December 31, 2011, we had a net fuel under-recovery balance of $7.0 million, including an under-recovery balance of $9.1 million in Texas partially offset by an over-recovery balance of $2.1 million in New Mexico.

40

Cash from operations has been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. 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.

We filed a request with the PUCT, the City of El Paso and other Texas cities on February 1, 2012 for a $26.3 million increase in rates charged to customers in Texas. The rate filing was made in response to a resolution adopted by the El Paso City Council requiring us to show cause why our base rates for customers in the El Paso city limits should not be reduced. The City has until August 4, 2012 to make a determination regarding our base rates in the City of El Paso. The rate filing used a historical test year ended September 30, 2011, adjusted for known and measurable items, and a return on equity of 10.6%. The filing at the PUCT also includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On November 15, 2011, the El Paso City Council adopted a resolution which established current rates as temporary rates for our customers residing within the city limits of El Paso. Temporary rates will be effective from November 15, 2011 until a final determination is made by the PUCT on our rates in the rate proceeding initiated by the City's Show Cause Order. Upon a final determination by the PUCT, the PUCT may order a refund to customers of money collected in excess of the rate finally ordered, including interest, or shall authorize us to surcharge bills to recover the amount, including interest, by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered. The rates proposed by the Company in the Texas rate case included increases for some customer classes and decreases for other customer classes. As a result, consistent implementation of the proposed rates may require the PUCT to reflect the differences in temporary and final rates from November 15, 2011 for each affected class.

While cities in Texas have jurisdiction over rates in their city limits, the PUCT has appellate authority over city rates decisions on a “de novo” basis, therefore, the ultimate authority to set our Texas electric rates is vested in the PUCT. We cannot predict the outcome of this proceeding. If the filed rate case results in implementing lower rates, the resulting lower rates would have a negative impact on our revenues, net income and cash from operations.

We cannot predict the outcome of the February 1, 2012 rate filing, and we are unable to predict the effect, if any, this would have on our future operations, cash flows and financial condition.

We maintain a $200 million revolving credit facility 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. In November 2011, we refinanced and extended our $200 million revolving credit facility, which includes an option, subject to lenders' approval, to expand the size to $300 million. The amended facility reduces our borrowing costs and extends the maturity from September 2014 to September 2016. The total amount borrowed for nuclear fuel by RGRT was $123.4 million at December 31, 2011 of which $13.4 million had been borrowed under the revolving credit facility and $110 million was borrowed through senior notes. At December 31, 2010, the total amount borrowed for nuclear fuel by RGRT was $114.7 million of which $4.7 million was borrowed under the revolving credit facility 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. At December 31, 2011, $20.0 million was outstanding under the revolving credit facility for working capital and general corporate purposes.

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 anticipate issuing long-term debt in the capital markets to finance capital requirements. In October 2011, we received approval from the NMPRC and the FERC to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides us with the flexibility to access the debt capital markets when needed and when conditions are favorable.

41

Contractual Obligations. Our contractual obligations as of December 31, 2011 are as follows (in thousands):

	Payments due by period
	Total		2012		2013 and 2014		2015 and 2016		2017 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,406,844	$	35,250	$	70,500	$	70,500	$	1,230,594
Pollution control bonds (2)	480,458		44,214		20,274		20,274		395,696
RGRT Senior notes (3)	144,129		5,054		10,107		24,350		104,618
Financing Obligations (including interest):
Revolving credit facility (4)	33,893		33,893		—		—		—
Purchase Obligations:
Power contracts	5,730		3,042		2,688		—		—
Fuel contracts:
Coal (5)	45,623		10,111		20,221		15,291		—
Gas (5)	281,054		41,465		62,898		64,556		112,135
Nuclear fuel (6)	139,505		30,542		29,324		31,310		48,329
Retirement Plans and Other Postretirement benefits (7)	18,344		18,344		—		—		—
Decommissioning trust funds (8)	163,016		4,636		9,272		9,272		139,836
Operating leases (9)	11,575		1,030		1,870		915		7,760
Total	$	2,730,171	$	227,581	$	227,154	$	236,468	$	2,038,968

 _____________________

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

(2) We have four series of pollution control bonds which are scheduled for remarketing and/or mandatory tender, one in 2012 and the other three in 2040.

(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 $200 million RCF used for, among other things, working capital and general corporate purposes. At December 31, 2011, $20 million was outstanding under this facility for working capital and general corporate purposes. Amounts borrowed by RGRT may be used, among other things, to finance nuclear fuel. At December 31, 2011, $13.4 million was borrowed for nuclear fuel. The balance includes interest based on actual interest rates at the end of 2011.

(5) Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2011. 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 2011.

(7) These obligations include our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2012. We have a minimum funding requirement of $14 million related to our retirement income plan for 2012. However, we may decide to fund at higher levels and expect to contribute $19.8 million and $2.5 million to our retirement plans and postretirement benefit plan, respectively, in 2012, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note M, Employee Benefits. Minimum funding requirements for 2012 and beyond are not included due to the uncertainty of interest rates and the related return on assets.

(8) These obligations represent funding estimates based on amounts requested in PUCT Docket No. 40094 which was filed February 1, 2012. Decommissioning trust funding could be adjusted based on the final outcome of this case.

(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 and parking facilities which expire within the next five years.

42

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.

43

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 $89.3 million and $82.9 million as of December 31, 2011 and 2010, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.8 million and $1.2 million based on their fair values at December 31, 2011 and 2010, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $74.9 million and $68.0 million at December 31, 2011 and 2010, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $15.0 million and $13.6 million based on their fair values at December 31, 2011 and 2010, 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, 2012, 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.

44

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, 2011. 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, 2011, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s internal control over financial reporting. This report appears on page 47 of this report.

45

Item 8.Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	47
Consolidated Balance Sheets as of December 31, 2011 and 2010	48
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009	50
Consolidated Statements of Comprehensive Operations for the years ended December  31, 2011, 2010 and 2009	51
Consolidated Statements of Changes in Common Stock Equity for the years ended December  31, 2011, 2010 and 2009	52
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	53
Notes to Consolidated Financial Statements	54

46

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, 2011 and 2010, 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, 2011. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2011, 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 24, 2012

47

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

ASSETS (In thousands)	December 31,
	2011			2010
Utility plant:
Electric plant in service	$	2,789,773		$	2,522,862
Less accumulated depreciation and amortization	(1,121,653		)	(1,047,498		)
Net plant in service	1,668,120			1,475,364
Construction work in progress	167,394			285,086
Nuclear fuel; includes fuel in process of $49,545 and $47,746, respectively	171,433			150,774
Less accumulated amortization	(59,882		)	(45,471		)
Net nuclear fuel	111,551			105,303
Net utility plant	1,947,065			1,865,753
Current assets:
Cash and cash equivalents	8,208			79,184
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,015 and $2,885, respectively	76,348			71,685
Accumulated deferred income taxes	13,752			25,818
Inventories, at cost	40,222			36,132
Income taxes receivable	2,269			12,656
Undercollection of fuel revenues	9,130			—
Prepayments and other	4,810			4,543
Total current assets	154,739			230,018
Deferred charges and other assets:
Decommissioning trust funds	167,963			153,878
Regulatory assets	101,027			88,557
Other	26,057			26,560
Total deferred charges and other assets	295,047			268,995
Total assets	$	2,396,851		$	2,364,766

See accompanying notes to consolidated financial statements.

48

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)

CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2011			2010
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,295,888 and 65,121,689 shares issued, and 156,185 and 143,371 restricted shares, respectively	$	65,452		$	65,265
Capital in excess of stated value	309,777			305,068
Retained earnings	887,174			810,858
Accumulated other comprehensive loss, net of tax	(77,505		)	(33,177		)
	1,184,898			1,148,014
Treasury stock, 25,492,919 and 22,693,995 shares, respectively, at cost	(424,647		)	(337,639		)
Common stock equity	760,251			810,375
Long-term debt	816,497			849,745
Total capitalization	1,576,748			1,660,120
Current liabilities:
Current maturities of long-term debt	33,300			—
Short-term borrowings under the revolving credit facility	33,379			4,704
Accounts payable, principally trade	51,704			41,795
Taxes accrued	30,700			29,172
Interest accrued	12,123			12,099
Overcollection of fuel revenues	2,105			18,976
Other	21,921			24,207
Total current liabilities	185,232			130,953
Deferred credits and other liabilities:
Accumulated deferred income taxes	299,475			286,730
Accrued pension liability	129,627			93,471
Accrued postretirement benefit liability	100,455			61,594
Asset retirement obligation	56,140			92,911
Regulatory liabilities	21,049			14,489
Other	28,125			24,498
Total deferred credits and other liabilities	634,871			573,693
Commitments and contingencies
Total capitalization and liabilities	$	2,396,851		$	2,364,766

See accompanying notes to consolidated financial statements.

49

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except for share data)

	Years Ended December 31,
	2011			2010			2009
Operating revenues	$	918,013		$	877,251		$	827,996
Energy expenses:
Fuel	223,507			199,829			185,837
Purchased and interchanged power	75,149			91,916			108,603
	298,656			291,745			294,440
Operating revenues net of energy expenses	619,357			585,506			533,556
Other operating expenses:
Other operations	229,570			224,221			215,841
Maintenance	62,092			56,823			59,606
Depreciation and amortization	81,331			81,011			74,946
Taxes other than income taxes	55,561			54,489			49,998
	428,554			416,544			400,391
Operating income	190,803			168,962			133,165
Other income (deductions):
Allowance for equity funds used during construction	8,161			10,816			9,311
Investment and interest income, net	5,664			5,315			3,813
Miscellaneous non-operating income	885			1,368			1,107
Miscellaneous non-operating deductions	(3,187		)	(3,206		)	(3,483		)
	11,523			14,293			10,748
Interest charges (credits):
Interest on long-term debt and revolving credit facility	54,115			50,826			50,512
Other interest	989			254			396
Capitalized interest	(5,177		)	(2,487		)	(943		)
Allowance for borrowed funds used during construction	(4,848		)	(6,671		)	(6,029		)
	45,079			41,922			43,936
Income before income taxes and extraordinary item	157,247			141,333			99,977
Income tax expense	53,708			51,016			33,044
Income before extraordinary item	103,539			90,317			66,933
Extraordinary gain related to Texas regulatory assets, net of tax	—			10,286			—
Net income	$	103,539		$	100,603		$	66,933
Basic earnings per share:
Income before extraordinary item	$	2.49		$	2.08		$	1.50
Extraordinary gain related to Texas regulatory assets, net of tax	—			0.24			—
Net income	$	2.49		$	2.32		$	1.50
Diluted earnings per share:
Income before extraordinary item	$	2.48		$	2.07		$	1.50
Extraordinary gain related to Texas regulatory assets, net of tax	—			0.24			—
Net income	$	2.48		$	2.31		$	1.50
Dividends declared per share of common stock	$	0.66		$	—		$	—
Weighted average number of shares outstanding	41,349,883			43,129,735			44,524,146
Weighted average number of shares and dilutive potential shares outstanding	41,587,059			43,294,419			44,595,067

See accompanying notes to consolidated financial statements.

50

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)

	Years Ended December 31,
	2011			2010			2009
Net income	$	103,539		$	100,603		$	66,933
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net loss arising during period	(77,678		)	(9,874		)	(48,580		)
Prior service benefit	—			26,605			—
Reclassification adjustments included in net income for amortization of:
Prior service cost	(5,812		)	(2,754		)	(2,754		)
Net loss	6,505			3,374			1,625
Net unrealized gains on marketable securities:
Net holding gains arising during period	1,570			6,665			12,816
Reclassification adjustments for net losses included in net income	1,358			122			2,218
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	361			338			317
Total other comprehensive income (loss) before income taxes	(73,696		)	24,476			(34,358		)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	30,134			(6,287		)	16,957
Net unrealized gains on marketable securities	(563		)	(1,357		)	(3,007		)
Losses on cash flow hedges	(203		)	(122		)	(115		)
Total income tax benefit (expense)	29,368			(7,766		)	13,835
Other comprehensive income (loss), net of tax	(44,328		)	16,710			(20,523		)
Comprehensive income	$	59,211		$	117,313		$	46,410

See accompanying notes to consolidated financial statements.

51

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, 2008	64,732,652		$	64,733		$	295,346		$	643,322		$	(29,364	)	19,848,900	$	(279,808	)	$	694,229
Restricted common stock grants and deferred compensation	114,703		115			2,162													2,277
Stock awards withheld for taxes	(8,249	)	(8		)	(157		)											(165		)
Forfeitures and lapsed restricted common stock	(12,850	)	(13		)														(13		)
Deferred taxes on stock incentive plan						328													328
Stock options exercised	267,900		267			3,501													3,768
Net income									66,933										66,933
Other comprehensive loss												(20,523		)					(20,523		)
Treasury stock acquired, at cost															1,320,384	(24,105		)	(24,105		)
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

See accompanying notes to consolidated financial statements.

52

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2011			2010			2009
Cash Flows From Operating Activities:
Net income	$	103,539		$	100,603		$	66,933
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	81,331			81,011			74,946
Amortization of nuclear fuel	37,018			31,316			22,305
Extraordinary gain related to Texas regulatory assets, net of tax	—			(10,286		)	—
Deferred income taxes, net	45,688			27,456			40,846
Allowance for equity funds used during construction	(8,161		)	(10,816		)	(9,311		)
Other amortization and accretion	19,875			16,740			14,440
Other operating activities	1,036			(881		)	1,154
Change in:
Accounts receivable	(4,663		)	(1,303		)	26,125
Inventories	(3,750		)	1,143			2,135
Net overcollection (undercollection) of fuel revenues	(26,001		)	958			64,875
Prepayments and other	(2,538		)	(544		)	(790		)
Accounts payable	4,401			(9,634		)	(1,988		)
Taxes accrued	11,915			18,523			(17,704		)
Interest accrued	24			1,816			2,764
Other current liabilities	(2,286		)	(689		)	750
Deferred charges and credits	(5,911		)	(6,063		)	(18,370		)
Net cash provided by operating activities	251,517			239,350			269,110
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(178,041		)	(169,966		)	(209,974		)
Cash additions to nuclear fuel	(39,551		)	(34,277		)	(34,904		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(13,009		)	(17,487		)	(15,340		)
Nuclear fuel	(5,177		)	(2,487		)	(943		)
Allowance for equity funds used during construction	8,161			10,816			9,311
Decommissioning trust funds:
Purchases, including funding of $8.3 million, $8.2 million and $7.9 million, respectively	(95,441		)	(73,192		)	(90,118		)
Sales and maturities	82,926			61,656			79,935
Proceeds from sale of investments in debt securities	2,000			—			—
Other investing activities	727			286			1,695
Net cash used for investing activities	(237,405		)	(224,651		)	(260,338		)
Cash Flows From Financing Activities:
Repurchases of common stock	(86,508		)	(33,726		)	(24,105		)
Dividends paid	(27,223		)	—			—
Proceeds from issuance of long-term debt	—			110,000			—
Borrowings under the revolving credit facility:
Proceeds	120,450			37,628			186,471
Payments	(91,775		)	(139,922		)	(173,126		)
Other financing activities	(32		)	(1,285		)	2,136
Net cash used for financing activities	(85,088		)	(27,305		)	(8,624		)
Net increase (decrease) in cash and cash equivalents	(70,976		)	(12,606		)	148
Cash and cash equivalents at beginning of period	79,184			91,790			91,642
Cash and cash equivalents at end of period	$	8,208		$	79,184		$	91,790

See accompanying notes to consolidated financial statements.

53

INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Note A. Summary of Significant Accounting Policies	55
Note B. New Accounting Standards	57
Note C. Regulation	58
Note D. Regulatory Assets and Liabilities	64
Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	65
Note F. Accounting for Asset Retirement Obligations	68
Note G. Common Stock	69
Note H. Accumulated Other Comprehensive Income (Loss)	74
Note I. Long-Term Debt and Financing Obligations	74
Note J. Income Taxes	76
Note K. Commitments, Contingencies and Uncertainties	78
Note L. Litigation	82
Note M. Employee Benefits	83
Note N. Franchises and Significant Customers	93
Note O. Financial Instruments and Investments	94
Note P. Supplemental Statements of Cash Flow Disclosures	98
Note Q. Selected Quarterly Financial Data (Unaudited)	99

54

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 regulartory 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 2011, 2010 and 2009 was 2.80%, 3.21%, and 3.22%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 rate used in 2011 was 8.54% . The AFUDC rate utilized for the first six months of 2010 was 9.01% and 8.47% thereafter. The AFUDC rate utilized in 2009 was 8.94%.

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 income (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 an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled

56

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

revenues of $19.6 million and $16.6 million at December 31, 2011 and 2010, 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 2011, 2010 and 2009 are as follows (in thousands):

	2011		2010		2009
Balance at beginning of year	$	2,885	$	1,191	$	3,123
Additions:
Charged to costs and expense	6,209		4,756		3,289
Recovery of previous write-offs	2,034		852		1,316
Uncollectible receivables written off	8,113		3,914		6,537
Balance at end of year	$	3,015	$	2,885	$	1,191

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. 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. For a full discussion of the Company’s accounting policies for its employee benefits. See Note M.

Reclassification. Certain amounts in the consolidated financial statements for 2010 and 2009 have been reclassified to conform with the 2011 presentation.

B.New Accounting Standards

In June 2011, the FASB issued new guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The new guidance requires an entity

57

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both presentations, an entity would have been required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. Historically, the Company has used the consecutive two-statement approach; however, this new guidance could require additional disclosure on the Company's statement of operations and related notes. In December 2011, the FASB issued new guidance to defer the effective date for amendments to the presentation of reclassification of items out of accumulated other comprehensive income. Deferring the effective date will allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, the Company will continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before the guidance issued in June 2011 until further guidance becomes available.

In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include: (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires: (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. This guidance requires additional disclosure on fair value measurements but did not impact the Company's consolidated financial statements.

C.    Regulation

General

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

Texas Regulatory Matters

2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The filing included a base rate increase which was based upon an adjusted test year ended June 30, 2009.

On July 30, 2010, the PUCT approved a settlement in the 2009 Texas retail rate case in PUCT Docket No. 37690. The settlement called for an annual non-fuel base rate increase of $17.15 million effective for usage beginning July 1, 2010. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. This increase was partially offset by the provision that, consistent with a prior rate agreement, effective July 1, 2010, the Company shares 90% of off-system sales margins with customers and retains 10% of such margins. Previously, the Company retained 75% of off-system sales margins. All additions to electric plant in service since June 30, 1993 through June 30, 2009 were deemed to be reasonable and necessary with the exception of one small addition. The Company's new customer information system completed in April 2010 was also included in base rates with a 10-year amortization. The settlement provided for the reconciliation of fuel costs incurred through June 30, 2009 except for the recovery of final Four Corners' coal mine reclamation costs. The fuel reconciliation (Docket No. 38361, discussed below) was bifurcated from the rate case to allow for litigation of the final coal mine reclamation costs. The PUCT also approved the use of a formula-based fuel factor which provides for more timely recovery of fuel costs. The PUCT approved a $19.7 million or 11% reduction in the Company's fixed fuel factor as the initial rate under the approved fuel factor formula. The PUCT also approved an energy efficiency cost-recovery

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

factor that includes the recovery of deferred energy efficiency costs over a three-year period.

2012 Texas Retail Rate Case. The Company filed a request with the PUCT (Docket No. 40094), the City of El Paso, and other Texas cities on February 1, 2012 for a $26.3 million increase in rates charged to customers in Texas. The rate filing was made in response to a resolution adopted by the El Paso City Council requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The City has until August 4, 2012 to make a determination regarding the Company's base rates in the City of El Paso. The rate filing used a historical test year ended September 30, 2011, adjusted for known and measurable items, and a return on equity of 10.6%. The filing at the PUCT also includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On November 15, 2011, the El Paso City Council adopted a resolution which established current rates as temporary rates for the Company's customers residing within the city limits of El Paso. Temporary rates will be effective from November 15, 2011 until a final determination is made by the PUCT on the Company's rates in the rate proceeding initiated by the City's Show Cause Order. Upon a final determination by the PUCT, the PUCT may order a refund to customers of money collected in excess of the rate finally ordered, including interest, or shall authorize the Company to surcharge bills to recover the amount, including interest, by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered. The rates proposed by the Company in the Texas rate case included increases for some customer classes and decreases for other customer classes. As a result, consistent implementation of the proposed rates may require the PUCT to reflect the differences in temporary and final rates from November 15, 2011 for each affected class.

While cities in Texas have jurisdiction over rates in their city limits, the PUCT has appellate authority over city rate decisions on a “de novo” basis; therefore, the ultimate authority to set the Company's Texas electric rates is vested in the PUCT. The Company cannot predict the outcome of this proceeding. If the rate case results in implementing lower rates, the resulting lower rates would have a negative impact on the Company's revenues, net income and cash from operations.

Fuel Reconciliation Case (Severed from 2009 Rate Case). Pursuant to the stipulation in the Company's 2009 rate case, the PUCT established Docket No. 38361 to address the one fuel reconciliation issue not settled by the parties. That single issue was a determination of the proper amount of the Four Corners' coal mine final reclamation costs to be recovered from the Company's Texas retail customers. The hearing on the merits of the case was held on August 11, 2010. On November 23, 2010 the Administrative Law Judge (the “ALJ”) issued the Proposal for Decision which approved the Company's request. The PUCT issued a final order approving the Proposal for Decision on January 27, 2011.

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. The Company received approval on July 30, 2010 in PUCT Docket No. 37690 (discussed above), 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.

The Company has filed the following petitions 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 dates the Company filed the petitions and the dates a final order was issued by the PUCT approving the refunds to customers. The fuel cost over-recovery periods represent the months in which the over-recoveries took place and the refund periods represent the billing month(s) in which customers received the refund amounts shown, including interest:

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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 (In thousands)
37788	December 17, 2009	February 11, 2010	September – November 2009	February 2010	$	11,800
38253	May 12, 2010	July 15, 2010	December 2009 – March 2010	July – August 2010	11,100
38802	October 20, 2010	December 16, 2010	April – September 2010	December 2010	12,800
39159	February 18, 2011	May 3, 2011	October – December 2010	April 2011	11,800

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

Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor		Effective Billing Month
38895	November 23, 2010	January 6, 2011	(14.7	)%	January 2011
39599	July 15, 2011	August 30, 2011	9.4	%	August 2011

As noted above, the rate filing filed with the PUCT on February 1, 2012 (Docket No. 40094), includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. However, this filing does not request a change in the fixed fuel factor.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2012. On May 2, 2011, the Company filed with the PUCT an application for approval to revise its energy efficiency cost recovery factor (“EECRF”), which was assigned PUCT Docket No. 39376. A unanimous settlement resolving all issues was filed with the PUCT on July 15, 2011. The settlement allows the Company to recover $8.3 million and supports the Company's request to revise its demand and energy goals and EECRF cost caps as well as the Company's request to increase its 2012 EECRF, effective beginning with the first billing cycle of its January 2012 billing month. A final order in the case was issued August 23, 2011, approving the settlement.

Petition for Approval to Revise Military Base Discount Recovery Factor. On July 14, 2011, the Company filed with the PUCT a petition requesting approval to revise its Military Base Discount Recovery Factor (“MBDRF”) tariff to account for under-recovery of discount charges during 2010 and for 2011 discounts. A final order was issued January 12, 2012 revising the MBDRF to 0.936% and allowing $3.9 million dollars of under-recovered discount charges to begin February 1, 2012.

Application for a Certificate of Convenience and Necessity (“CCN”) for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned PUCT Docket No. 38717. A unanimous settlement to approve the CCN was filed on March 2, 2011, and a final order granting the CCN was approved on April 8, 2011.

Project to Investigate Early February 2011 Outages and Curtailments. On February 8, 2011, the PUCT opened Project No. 39134, Investigation into Power Outages in El Paso Electric's Service Territory. In this project, the PUCT is investigating the Company's power plant outages and customer curtailments that occurred February 2-4, 2011, as a result of the extreme cold weather in the El Paso area. The PUCT Staff conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event. On May 13, 2011, the PUCT Staff issued a report stating that, as of then, it had not identified violations by the Company of the Texas electric utility regulatory statute or PUCT rules. The report also stated that the PUCT Staff would continue to monitor the extreme cold weather event results and subsequent forthcoming information as the Company and other regulatory agencies complete their ongoing investigations.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On February 15, 2011, the City Council of El Paso passed a motion that, upon the conclusion of other hearings and investigations into the extreme cold weather event, the Mayor would call for Special City Council meetings or public hearings to evaluate how the three utility companies operating within the city, including the Company, performed during the extreme weather event. The El Paso City Council retained a consultant to assess the Company's activities during the weather event and the Company's subsequent actions to prevent outages during a similar future event. The El Paso City Council's consultant presented the following three recommendations to the El Paso City Council on December 20, 2011: (i) request the Company to prepare and present an updated reliability study; (ii) request the Company and El Paso Water Utilities to present their coordinated plans for power and water supply to critical loads during severe weather events; and (iii) request the Company to file an updated emergency operations plan with both the PUCT and the El Paso City Council which will be completed in 2012. The El Paso City Council unanimously passed a motion to approve the three recommendations. At the January 10, 2012 El Paso City Council Meeting, the Company presented information requested in recommendations (i) and (ii) above.

Application of El Paso Electric Company to Amend its Certificate of Convenience and Necessity for Five Solar Power Generation Projects. On December 9, 2011, the Company filed a petition seeking a CCN to construct five solar powered generation projects, totaling approximately 2.6MW, at four locations within the City of El Paso and one location in the Town of Van Horn. This case was assigned PUCT Docket No. 39973 and is still pending.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On May 29, 2009, the Company filed a general rate case using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT. A comprehensive unopposed stipulation (the “2009 New Mexico Stipulation”) was reached in this general rate case and filed on October 8, 2009. The 2009 New Mexico Stipulation provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and a revision of depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company's Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) without conditions or variance. In addition, it modified the market pricing of capacity and energy provided by Palo Verde Unit 3 using a methodology based upon a previous purchased power contract with Credit Suisse Energy, LLC. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation, and the stipulated rates went into effect with January 2010 bills.

Application for Approval to Recover Regulatory Disincentives and Incentives. On August 31, 2010, the Company filed an application for approval of its proposed rate design methodology to recover regulatory disincentives and incentives associated with the Company's energy efficiency and load management programs in New Mexico. On March 18, 2011, the Company entered into an uncontested stipulation which would provide for a rate per kWh of energy efficiency savings that would be recovered through the efficient use of energy rider. A hearing on the uncontested stipulation was held on April 26, 2011 and briefs were filed on September 26, 2011. A final order was issued on November 22, 2011 in which the NMPRC did not adopt the unopposed stipulation, but modified the structure of the energy rider to reduce the return to two percent and made the mechanism temporary.  The Company filed a Notice of Appeal with the Supreme Court of the State of New Mexico on January 20, 2012 on the grounds that the NMPRC's decision is arbitrary and without substantial evidence.

Application for a CCN for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned NMPRC Case No. 10-00301-UT. On April 13, 2011 an unopposed stipulation was filed in this case seeking approval of a CCN for the Company to construct, own and operate the 87 MW generating unit. A final order on this case approving the CCN was issued on June 23, 2011.

Application for Approval of 2011 New and Modified Energy Efficiency Programs. On February 15, 2011, the Company filed its Application for Approval of New and Modified Energy Efficiency Programs for 2011 with the NMPRC. On June 22, 2011, parties to this case entered into a partial stipulation, agreeing on all issues, except for a military base free-ridership issue. On June 24, 2011, the New Mexico Attorney General filed a statement in opposition to the proposed partial stipulation. On January 25, 2012, a hearing examiner issued a recommended decision modifying the stipulation by approving the Energy Efficiency programs and budgets with the exception of the Commercial Lighting Program, approving the adder for 2011 but not for 2012 or 2013 and excluding the Military Research & Development Class from participation in the rate rider and reducing the Company's required saving goals accordingly. On February 2, 2012, the Company filed certain exceptions to the recommended decision and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

requested an interim order related to this matter.

2011 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2011, the Company filed its Application for Approval of its 2011 Renewable Procurement Plan with the NMPRC, which was assigned NMPRC Case No. 11-00263-UT. The filing identified renewable resources intended to meet the Company's Renewable Portfolio Standard (“RPS”) requirements in 2012 and 2013. The renewable resources in the 2011 Renewable Procurement Plan, which were previously approved by the NMPRC, will allow the Company to meet the full RPS requirement of 10% of the Company's jurisdictional retail energy sales for 2012 and 2013. The Company's 2011 Renewable Procurement Plan also addresses the diversity targets in 2012 and 2013 required by NMPRC Rule 572 and demonstrates that the Company will meet those targets. The 2011 Renewable Procurement Plan also demonstrates that the Company will meet its solar diversity target in 2012 and comply with the terms of a previously-approved variance for 2011. A hearing in this case was held on October 13, 2011. A final order was issued on December 15, 2011 approving the 2011 Renewable Procurement Plan.

Investigation into Rates for Church Customers. On July 12, 2011, the NMPRC initiated an investigation into the rates the Company charges its church customers which were approved in Case No. 09-00171-UT. The investigation, Case No. 11-00276-UT, was ordered to determine whether the Company's rates to its church customers are unjust and unreasonable and should be revised. The Company filed a response on August 1, 2011. A mediation conference was held on August 23, 2011 which resulted in an Unopposed Joint Stipulation, filed on October 14, 2011. The stipulation limits billing impacts to religious organizations that take service under the Company's standard small commercial rate. The stipulation was approved by the NMPRC on October 27, 2011.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the NMPRC in Case No. 11-00349-UT to amend and restate the Company's $200 million revolving credit facility ("RCF"), which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and Rio Grande Resources Trust ("RGRT") amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million during the term of the RCF, subject to lender's approval. All other terms remain substantially the same.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company's transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in Arizona. The Company asserted that TEP's rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Company's favor, finding that TEP does not have transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP's request for a rehearing of the FERC's decision was granted in part and denied in part in an order issued October 4, 2006, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.

On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time.

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The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for service relating to the LEF. On December 3, 2008, the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC's decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company's transmission system on a going forward basis. On July 7, 2010, the FERC denied the Company's request for rehearing. On July 23, 2010, the Company filed a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) and on August 18, 2010, TEP filed a motion to intervene in the proceeding. On January 14, 2011, the Company and TEP filed a joint consent motion, asking the Court to hold the proceedings in abeyance while the parties engaged in settlement discussions. The Court granted the motion on January 19, 2011.

On August 31, 2011, the FERC issued an order approving a settlement between TEP and the Company that became effective November 1, 2011. The settlement reduces TEP's transmission rights under the Transmission Agreement from 200 MW to 170 MW, and TEP and the Company have entered into two new firm transmission capacity agreements at applicable tariff rates for a total of 40 MW. Those two new service agreements were entered into and became effective November 1, 2011. Also under the terms of the settlement, TEP made a lump-sum cash payment to the Company of approximately $5.4 million for the period February 1, 2006 through September 30, 2011, including interest income. This adjustment was recorded in the three months ended September 30, 2011. The Company shared with its customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries. As part of the settlement, the Company withdrew its appeal before the Court of Appeals.

In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. As part of the settlement, this lawsuit was dismissed.

With the implementation of the settlement effective November 1, 2011, these matters between the Company and TEP were fully resolved.

Inquiry into Early February 2011 Outages and Curtailments. On February 14, 2011, the FERC directed its staff to initiate an inquiry into power plant outages and customer curtailments by power generators and gas suppliers in the Southwestern United States, including the Company, in early February 2011, as a result of the extreme cold weather. The FERC specifically stated that its inquiry is not an enforcement investigation. On August 16, 2011, the FERC released its staff report, Docket No. AD11-9-000, where it made recommendations to help prevent a recurrence of such outages in the future, and making no finding of violations or assessments of penalties.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the FERC in Docket No. ES11-43-000 to amend and restate the Company's $200 million RCF, which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and RGRT amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million, subject to lender's approval. All other terms remain substantially the same.

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

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spent fuel storage and disposal costs.

Nuclear Regulatory Commission ("NRC"). The NRC has jurisdiction over the Company's licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.

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.

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, 2011		December 31, 2010
Regulatory assets
Regulatory tax assets (a)	(b)	$	52,281	$	37,230
Loss on reacquired debt (c)	May 2035	20,044		20,897
Final coal reclamation (a)	July 2016	6,655		10,282
Nuclear fuel postload daily financing charge	(d)	3,470		2,007
Unrecovered issuance costs due to reissuance of PCBs (c)	April 2040	578		599
Texas energy efficiency	(e)	4,497		5,460
Texas 2009 rate case costs (f)	June 2012	1,146		3,298
Texas 2012 rate case costs	(g)	648		—
Texas military base discount and recovery factor	(h)	2,526		761
New Mexico 2009 rate case procurement plan costs (f)	December 2011	—		232
New Mexico procurement plan costs	(g)	139		122
New Mexico 2009 rate case renewable energy credits (f)	December 2011	—		1,139
New Mexico renewable energy credits	(g)	2,884		930
New Mexico 2009 rate case costs (f)	December 2012	253		506
New Mexico 2010 FPPCAC audit	(g)	427		—
New Mexico Palo Verde deferred depreciation	(b)	5,176		4,773
New Mexico energy efficiency	(e)	303		321
Total regulatory assets		$	101,027	$	88,557
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	16,138	$	9,326
Accumulated deferred investment tax credit (i)	(b)	4,911		5,163
Total regulatory liabilities		$	21,049	$	14,489

________________

(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.

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(c) This item is recovered as a component of the weighted cost of debt and amortized over 30 years beginning in 2005.

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

(e) This asset is recovered 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.

(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, 2011 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	768,284	$	(240,862	)	$	527,422
Steam and other	557,286		(223,109		)	334,177
Total production	1,325,570		(463,971		)	861,599
Transmission	394,385		(238,940		)	155,445
Distribution	864,746		(308,644		)	556,102
General	141,921		(78,323		)	63,598
Intangible	63,151		(31,775		)	31,376
Total	$	2,789,773	$	(1,121,653	)	$	1,668,120

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):

2009	$	4,542
2010	6,312
2011	6,668
2012 (estimated)	6,124
2013 (estimated)	5,403
2014 (estimated)	4,292
2015 (estimated)	3,542
2016 (estimated)	3,045

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, 2011 and 2010 is as follows (in thousands):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2011						December 31, 2010
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	768,284		$	211,983		$	772,710		$	209,427
Accumulated depreciation	(240,862		)	(164,622		)	(225,461		)	(159,679		)
Construction work in progress	53,822			1,634			48,703			1,940
Total	$	581,244		$	48,995		$	595,952		$	51,688

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 will now expire in 2045, 2046 and 2047, respectively. For the last three quarters of 2011 combined, the extension of the operating licenses 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. The Company is required to maintain a minimum accumulation and a minimum 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, 2011, the Company’s decommissioning trust fund had a balance of $168.0 million, and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.

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 increase in the license life 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 will lower annual expenses in the future. 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. See “Spent Fuel Storage” and “Disposal of Low-Level Radioactive Waste” below.

Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the on-site facilities until accepted by the DOE for

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permanent disposal. The 2010 Study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2057. APS believes 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.

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 has previously reported that its spent nuclear fuel disposal facilities would not be in operation in the near future. In November 1997, the United States Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. The Company cannot predict when spent fuel shipments to the DOE will commence.

The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde that 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.

In December 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. APS pursued a damages claim for costs incurred through December 2006 in a trial that began on January 28, 2009. On June 18, 2010, the court awarded APS and the other Palo Verde Participants approximately $30 million. 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. APS is continuing to pursue settlement of damage claims for costs incurred after 2006.

Disposal of Low-level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. The construction and opening of low-level radioactive waste disposal sites have been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed sites. The opposition, delays, uncertainty and costs that have been experienced demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.

Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant's required licensing and design parameters. Validation of that data will continue as more information becomes available.

Following the March 11, 2011 earthquake and tsunami in Japan, the NRC launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force's recommendations.

On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

Until further action is taken by the NRC as a result of this event, the Company cannot predict any 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 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $2.75 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 $9.57 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 retirements which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s AROs are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The 2011 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, 2011 is $168.0 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 ARO liability and the revised ARO liability are as follows:

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 due to Palo Verde license extension.

	2011			2010			2009
ARO liability at beginning of year	$	92,911		$	85,358		$	78,037
Liabilities incurred	—			—			—
Liabilities settled	(793		)	(85		)	—
Revisions to estimate	(41,670		)	(377		)	—
Accretion expense	5,692			8,015			7,321
ARO liability at end of year	$	56,140		$	92,911		$	85,358

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

G.     Common Stock

Overview

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

Long-Term Incentive Plan

On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the “2007 LTIP”) and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options 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 2011:

	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, 2010	101,246	$	12.82
Options exercised	53,910	12.83					$	692	$	327
Options outstanding at December 31, 2011	47,336	12.80		0.99	$	1,034
Exercisable at December 31, 2011	47,336	12.80		0.99	1,034

The intrinsic value of stock options exercised in 2011, 2010 and 2009 were $1.0 million, $1.3 million and $1.5 million, respectively. No options were forfeited, vested or expired during 2011 and 2010.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

All stock options outstanding have vested. No compensation cost was recognized in 2009, 2010 and 2011 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 2011, 2010 and 2009 is presented below (in thousands):

	2011			2010			2009
Expense	$	2,258		$	1,589		$	1,537
Deferred tax benefit	790			556			538
Current tax expense (benefit) recognized (a)	(518		)	(169		)	134

_____________________

(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 2011, 2010 and 2009 is presented below (in thousands):

	2011		2010		2009
Aggregated intrinsic value	$	3,279	$	1,749	$	1,331
Fair value at grant date	1,799		1,265		1,714

The unvested restricted stock transactions for 2011 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, 2010	143,371		$	18.30
Restricted stock awards	118,110		28.98
Lapsed restrictions and vesting	(103,096	)	17.45
Forfeitures	(2,200	)	23.20
Restricted shares outstanding at December 31, 2011	156,185		26.87		$	2,136	$	5,410

_______________________

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

The weighted average fair values per share at grant date for restricted stock awarded during 2011, 2010 and 2009 were:

	2011		2010		2009
Weighted average fair value per share	$	28.98	$	20.03	$	14.59

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Detail of performance shares vested follows:

Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Compensation Costs Expensed Period	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
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
January 1, 2010	30.0	%	9,525	662		2007-2009	193

In 2012, 2013 and 2014, 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 174,038 shares that vested on January 1, 2012, the actual number of shares to be issued can range from zero to 392,328 shares.

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

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

	Number Outstanding		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a) (in thousands)		Aggregate Intrinsic Value (in thousands)
Performance shares outstanding at December 31, 2010	219,800		$	15.86
Performance share awards	112,164		23.45
Performance shares vested	(36,350	)	17.27
Performance shares lapsed	—		—
Performance shares forfeited	—		—
Performance shares outstanding at December 31, 2011	295,614		18.57		$	1,825	$	10,240

_______________________

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A summary of information related to performance shares for 2011, 2010 and 2009 is presented below:

	2011		2010		2009
Weighted average per share grant date fair value per share of performance shares awarded	$	23.45	$	19.82	$	12.00
Fair value of performance shares vested (in thousands)	628		663		—
Intrinsic value of performance shares vested (in thousands)	1,032		193		—
Compensation expense (in thousands) (a)	1,573		988		727
Deferred tax expense related to compensation expense (in thousands)	551		346		254

_____________________

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

Repurchase Program

Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Twelve Months Ended December 31,		Authorized Shares
Shares repurchased	25,406,184		2,782,455
Cost, including commission (in thousands)	$	423,647	$	86,508
2010 Plan balance at December 31, 2010					676,271
2011 Plan repurchase shares authorized (b)					2,500,000
Total remaining shares available for repurchase at December 31, 2011					393,816

______________________

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

(b) On March 21, 2011, the Board of Directors authorized an additional repurchase of the Company’s common stock (the “2011 Plan”).

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

Dividend Policy

On December 30, 2011, the Company paid $8.8 million of quarterly dividends to shareholders. The Company paid a total of $27.2 million in cash dividends during the twelve months ended December 31, 2011. On January 26, 2012, the Board of Directors declared a quarterly cash dividend of $0.22 per share payable on March 30, 2012 to shareholders of record on March 15, 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basic and Diluted Earnings Per Share

FASB guidance which 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,
	2011			2010			2009
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	41,349,883			43,129,735			44,524,146
Dilutive effect of unvested performance awards	206,658			101,780			27,876
Dilutive effect of stock options	30,518			62,904			43,045
Diluted number of common shares outstanding	41,587,059			43,294,419			44,595,067
Basic net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income allocated to participating restricted stock	(471		)	(403		)	(240		)
Net income available to common shareholders	$	103,068		$	100,200		$	66,693
Diluted net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income reallocated to participating restricted stock	(469		)	(401		)	(240		)
Net income available to common shareholders	$	103,070		$	100,202		$	66,693
Basic net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.83			2.32			1.50
Basic net income per common share	$	2.49		$	2.32		$	1.50
Diluted net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.82			2.31			1.50
Diluted net income per common share	$	2.48		$	2.31		$	1.50

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,
	2011	2010	2009
Restricted stock awards	81,653	75,270	66,628
Performance shares (a)	—	24,225	161,842
Stock options	—	—	53,610

_____________________

(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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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2008	$	(6,159	)	$	(9,834	)	$	(13,371	)	$	(29,364	)
Other comprehensive income (loss)	15,034			(49,709		)	317			(34,358		)
Income tax benefit (expense)	(3,007		)	16,957			(115		)	13,835
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	)

I.    Long-Term Debt and Financing Obligations

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

	December 31,
	2011			2010
	(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
4.80% 2005 Series A refunding bonds, due 2040 (5.32% 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
4.00% 2002 Series A refunding bonds, due 2032 (5.07% 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)	397,894			397,856
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,768			148,754
Total Senior Notes	546,662			546,610
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	849,797			849,745
Financing Obligations:
Revolving Credit Facility ($33,379 due in 2012) (4)	33,379			4,704
Total long-term debt and financing obligations	883,176			854,449
Current Portion (amount due within one year):
Current maturities of long-term debt	(33,300		)	—
Short-term borrowings under the revolving credit facility	(33,379		)	(4,704		)
	$	816,497		$	849,745

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 _____________________

(1) Pollution Control Bonds (“PCBs”)

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 4.00% 2002 Series A must be remarketed in August 2012 and is shown as current maturities of long-term debt on the Company's 2011 balance sheet.

(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.

(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 2011.

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

Prior to November 15, 2011, the Company had available a $200 million credit facility with a four-year term ending September 2014. The credit facility provided for the financing of nuclear fuel, which was accomplished through the RGRT that borrowed under the facility to acquire and process nuclear fuel. The Company was obligated to repay the RGRT’s borrowings with interest. Any amounts not borrowed by the RGRT could have been borrowed by the Company for working capital needs.

On November 15, 2011, the Company and RGRT entered into an amended and restated 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. Under the terms of the RCF, the Company and RGRT have available $200 million of credit for a term ending September 23, 2016. The Company may request that the RCF be increased up to a total of $300 million during the term of the RCF, subject to lender approval.

The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 2011. As of December 31, 2011, the total amount borrowed by RGRT was $13.4 million for nuclear fuel under the RCF, and $20.0 million was 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, 2011.

As of December 31, 2011, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2012	$	33,300
2013	—
2014	—
2015	15,000
2016	—

The $33.4 million outstanding on the RCF for working capital and general corporate purposes is anticipated to be paid in 2012.

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, 2011 and 2010 are presented below (in thousands):

	December 31,
	2011			2010
Deferred tax assets:
Benefit of tax loss carryforwards	$	21,737		$	286
Alternative minimum tax credit carryforward	19,863			18,370
Pensions and benefits	87,946			62,821
Asset retirement obligation	20,100			33,904
Deferred fuel	—			7,317
Other	20,524			21,093
Total gross deferred tax assets	170,170			143,791
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(424,319		)	(359,838		)
Decommissioning	(22,633		)	(37,936		)
Deferred fuel	(2,493		)	—
Other	(6,448		)	(6,929		)
Total gross deferred tax liabilities	(455,893		)	(404,703		)
Net accumulated deferred income taxes	$	(285,723	)	$	(260,912	)

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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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company recognized income tax expense for 2011, 2010 and 2009 as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Income tax expense:
Federal:
Current	$	5,084		$	19,251		$	(10,123	)
Deferred	46,612			31,279			39,537
Total federal income tax	51,696			50,530			29,414
State:
Current	2,936			4,308			2,321
Deferred	(924		)	1,947			1,309
Total state income tax	2,012			6,255			3,630
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044

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 2011 or 2009. As of December 31, 2011, the Company had $19.9 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2011, the Company had tax loss carryforwards of $21.1 million and $0.6 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,
	2011			2010			2009
Federal income tax expense computed on income at statutory rate	$	55,036		$	55,086		$	34,992
Difference due to:
State taxes, net of federal benefit	1,308			4,066			2,360
AEFUDC	(2,295		)	(3,578		)	(3,051		)
Permanent tax differences	(303		)	(3,103		)	(618		)
Patient Protection and Affordable Care Act	—			4,787			—
Other	(38		)	(473		)	(639		)
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044
Effective income tax rate	34.2		%	36.1		%	33.1		%
Effective income tax rate without PPACA	34.2		%	33.0		%	33.1		%

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 2007 and in the state jurisdictions for years prior to 1998. A deficiency notice relating to the Company’s 1998 through 2003 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 Patient Protection and Affordable Care Act (“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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The Company recorded an additional unrecognized tax position of $2.2 million and $6.3 million, respectively, related to the change in accounting method in 2011 and 2010. An additional unrecognized tax position may be recognized after the IRS audits the 2009 and 2010 tax returns. A reconciliation of the December 31, 2011, 2010 and 2009 amount of unrecognized tax benefits is as follows (in thousands):

	2011		2010		2009
Balance at January 1	$	7,300	$	600	$	500
Additions/(reductions) based on tax positions related to the current year	2,200		6,300		—
Additions for tax positions of prior years	—		400		400
Reductions for tax positions of prior years	—		—		(300		)
Balance at December 31	$	9,500	$	7,300	$	600

If recognized, $1.1 million of the unrecognized tax position at December 31, 2011, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $0.1 million for the year ended December 31, 2009.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the years ended December 31, 2011, 2010 and 2009, the Company recognized expense of $0.2 million and benefits of approximately $0.1 million and $0.2 million, respectively, in interest. The Company had approximately $0.4 million and $0.2 million for the payment of interest and penalties accrued at December 31, 2011 and 2010, respectively.

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 July 2031	August 2011
Power Purchase Agreement	Sun Edison 1		12	MW	25 years after operational start date	2012
Power Purchase Agreement	Sun Edison 2		10	MW	25 years after operational start date	2012
Power Purchase Agreement	NextEra Energy Resources		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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 NextEra Energy Resource 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 for two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which commercial operation is estimated to begin in 2012. 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

General. The Company is subject to laws and regulations with respect to air, soil and water quality, waste disposal and other environmental matters by federal, state, regional, tribal and local authorities. Those authorities govern facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these requirements can result in actions by regulatory agencies or other authorities 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 and regulations are subject to change and, as a result of those changes, 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”) 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. 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 from the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions starting in 2009. The U.S. Court of Appeals for the District of Columbia voided CAIR in 2008; however, the Company has complied with CAIR since 2009, and such rule is binding. 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		62

Cross-State Air Pollution Rule. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which is intended to replace CAIR. CSAPR requires 28 states, including Texas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were required to begin January 1, 2012, with further reductions required beginning January 1, 2014. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay CSAPR, including the supplemental final rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. The court is scheduled to hear the cases against the rule in April 2012. Under this timeframe, the court could issue its decision by summer or early fall 2012. As the outcome of the judicial review and any other legal or Congressional challenges are uncertain, the Company is unable to determine what impact CSAPR may ultimately have on its operations and consolidated financial results, but it could be material. Until the legal challenges to CSAPR are resolved, the Company's obligations under CAIR remains in effect.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, CO and SO₂. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. The Company is currently evaluating what impact this 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. In addition, the EPA is currently reviewing the PM NAAQS. The Company cannot at this time predict the impact of this review and any possible new standards on its operations or consolidated financial results, but it could be material. The EPA had been in the process of revising the NAAQS for ozone. However, in September 2011, President Obama ordered the EPA to withdraw its proposal. Work, however, is underway to support EPA's planned reconsideration of the standards in 2013.

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 power plants, which replaces the prior federal Clean Air Mercury Rule and requires significant reductions in emissions of mercury and other air toxics. Companies impacted by the new standards will have up to four (and in certain cases five) years to comply. The Company is currently evaluating the new standards and cannot at this time determine the impact they may have on its Four Corners plant, but the cost of compliance could be material.

Climate Change. 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 (“GHG”) emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of GHGs, such as carbon dioxide, could impose significant costs or limitations on the Company. In recent years, the U.S. Congress has considered new legislation to restrict or regulate GHG emissions, although federal efforts directed at enacting comprehensive climate change legislation stalled in 2010 and appear unlikely to recommence in the near future. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered by Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In September 2009, the EPA adopted a rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. GHG emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company's fossil fuel-fired power generating assets are subject to this rule, and the first report containing 2010 emissions was submitted to the EPA prior to the September 30, 2011 due date. The Company also has inventoried and implemented procedures for electrical equipment containing sodium hexafluoride ("SF6"), another GHG. The Company is tracking these GHG emissions pursuant to the EPA's new SF6 reporting rule that was finalized in late 2010 and became effective January 1, 2011. The first report to EPA under this rule was originally due on March 31, 2012, but in November 2011, EPA delayed its submittal to September 26, 2012.

The EPA has also proposed and finalized other rulemakings on GHG emissions that affect electric utilities. Under EPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications (referred to as the “PSD” program). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or 100,000 tons per year, depending on various factors), will be required to implement “best available control technology,” or “BACT”. Pursuant to the rule, the EPA may reduce the 75,000 tons threshold referenced above in 2012 or thereafter. The EPA has issued guidance on what BACT entails for the control of GHGs, and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of these new regulations on the Company's operations cannot be determined at this time, but the cost of compliance with new regulations could be material. Also, on December 23, 2010, the EPA announced a settlement agreement with states and environmental groups regarding setting new source performance standards for GHG emissions from new and existing coal-, gas- and oil-based power plants. Pursuant to this agreement, and certain agreed upon extensions, the EPA intends to issue proposed rules for new and modified electric generating units ("EGUs") in 2012. It is unclear when the EPA will propose a GHG New Source Performance Standard ("NSPS") for existing EGUs and how stringent it would be, but this rule is expected. The impact of these rules on the Company is unknown at this time, but they could result in significant costs.

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In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to consider how to address GHG emissions and are actively considering the development of emission inventories or regional GHG cap and trade programs.

It is not currently possible to predict with confidence how any pending, proposed or future GHG legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact the Company's business. However, any such legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or reduced demand for the power the Company generates, could require the Company to purchase rights to emit GHG, and 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 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. Substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. 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 at present to meaningfully quantify the costs of these potential impacts.

Contamination Matters. The Company has a provision for environmental remediation obligations of approximately $0.3 million at December 31, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):

	Years Ended December 31,
	2011			2010		2009
Clean Air Act (1)	$	716	—	$	615	$	810
Clean Water Act (2)	264			178		597

________________

(1)Includes $0.3 million related to alleged excess emissions at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009.

(2)2011 excludes a reduction of approximately $0.1 million related to an adjustment for estimated remediation costs for Copper generating station. 2009 also excludes a reduction of $0.6 million related to an adjustment for estimated remediation costs for a property previously owned by the Company.

The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community reservation in Arizona and designated it as a Superfund site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has an agreement with the EPA and a former property owner to resolve this matter and on June 30, 2011, the Company entered into a consent decree with the EPA at a cost to the Company of less than $0.1 million.

Environmental Litigation and Investigations. On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the CAA. APS responded to this request in 2009. The Company is unable to predict the timing or content of the EPA's response, if any, or any resulting actions.

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The Company received word 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 provisions of the CAA. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's 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 NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS advised that it believes the claims in this matter are without merit and will vigorously defend against them. The Company is unable to predict the outcome of these alleged violations.

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 and parking facilities 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 $1.1 million for 2011, 2010 and 2009. As of December 31, 2011, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2012	$	1,030
2013	951
2014	919
2015	477
2016	438

L.    Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, 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 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,
	2011						2010
	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	$	242,718		$	24,008		$	215,944		$	21,767
Service cost	6,590			260			5,888			176
Interest cost	12,871			1,116			12,507			1,122
Amendments	—			—			—			838
Actuarial loss	42,508			2,980			16,008			1,822
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Benefit obligation at end of year	296,293			26,547			242,718			24,008
Change in plan assets:
Fair value of plan assets at end of prior year	171,341			—			155,140			—
Actual return on plan assets	16,422			—			17,030			—
Employer contribution	12,000			1,817			6,800			1,717
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Fair value of plan assets at end of year	191,369			—			171,341			—
Funded status at end of year	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(1,844	)	$	—		$	(1,914	)
Noncurrent liabilities	(104,924		)	(24,703		)	(71,377		)	(22,094		)
Total	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(296,293	)	$	(26,547	)	$	(242,718	)	$	(24,008	)
Accumulated benefit obligation	(250,753		)	(26,547		)	(205,167		)	(23,538		)
Fair value of plan assets	191,369			—			171,341			—

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

	Years Ended December 31,
	2011				2010
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	129,820	$	8,990	$	95,828	$	6,364
Prior service cost	24		408		46		502
Total	$	129,844	$	9,398	$	95,874	$	6,866

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

	December 31,
	2011						2010
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.3	%	3.6	%	4.1	%	5.4	%	4.6	%	5.3	%
Rate of compensation increase	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 changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. A 1% increase in the discount rate would decrease the December 31, 2011 retirement plans' projected benefit obligation by 12.7%. A 1% decrease in the discount rate would increase the December 31, 2011 retirement plans' projected benefit obligation by 15.8%.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Years Ended December 31,
	2011					2010					2009
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	6,590		$	260	$	5,888		$	176	$	5,414		$	120
Interest cost	12,871			1,116		12,507			1,122		11,942			1,241
Amendments	—			—		—			838		—			—
Expected return on plan assets	(14,095		)	—		(13,867		)	—		(15,439		)	—
Amortization of:
Net loss	6,190			354		3,331			218		1,549			76
Prior service cost	21			94		21			94		21			94
Net periodic benefit cost	$	11,577		$	1,824	$	7,880		$	2,448	$	3,487		$	1,531

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

	Years Ended December 31,
	2011						2010						2009
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	40,181		$	2,980		$	12,844		$	1,822		$	48,531		$	1,892
Amortization of:
Net loss	(6,190		)	(354		)	(3,331		)	(218		)	(1,549		)	(76		)
Prior service cost	(21		)	(94		)	(21		)	(94		)	(21		)	(94		)
Total expense recognized in other comprehensive income	$	33,970		$	2,532		$	9,492		$	1,510		$	46,961		$	1,722

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

	Years Ended December 31,
	2011				2010				2009
	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	$	45,547	$	4,356	$	17,372	$	3,958	$	50,448	$	3,253

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2012 (in thousands):

	Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	11,300	$	560
Prior service cost	20		90

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	2011						2010						2009
			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	5.4	%	4.6	%	5.3	%	5.9	%	5.2	%	6.0	%	6.1	%	6.3	%	6.3	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		8.5	%	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 changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan.

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2011, 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, 2011
Equity securities	50	%
Fixed income	45	%
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 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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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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The fair value of the Company’s Retirement Plan assets at December 31, 2011 and 2010, 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, 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

Description of Securities	Fair Value as of December 31, 2010		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	$	4,975	$	4,975	$	—	$	—
U.S. Treasury Securities	83,601		83,601		—		—
Guaranteed Investment Contract	550		—		550		—
Common Stock	54,957		54,957		—		—
Mutual Funds	19,501		19,501		—		—
Limited Partnership Interest in Real Estate (a)	7,757		—		—		7,757
Total Plan Investments	$	171,341	$	163,034	$	550	$	7,757

 _____________________

(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, 2009	$	8,288
Unrealized loss in fair value	(531		)
Balance at December 31, 2010	7,757
Sale of land	(102		)
Unrealized gain in fair value	856
Balance at December 31, 2011	$	8,511

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, 2011 and 2010.

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

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $19.8 million to its retirement plans in 2012.

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
2012	$	9,132	$	1,844
2013	9,967		1,813
2014	10,932		1,777
2015	11,924		1,758
2016	13,021		1,801
2017-2021	83,027		9,430

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 currently based on the funding amounts established in PUCT Docket No. 37690. 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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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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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,
	2011			2010
Change in benefit obligation:
Benefit obligation at end of prior year	$	95,254		$	118,267
Service cost	2,988			3,558
Interest cost	5,379			6,664
Actuarial loss	32,694			(3,807		)
Amendments (a)	—			(26,605		)
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Benefit obligation at end of year	133,272			95,254
Change in plan assets:
Fair value of plan assets at end of prior year	33,660			29,348
Actual return on plan assets	—			2,514
Employer contribution	2,200			4,621
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Fair value of plan assets at end of year	32,817			33,660
Funded status (b)	$	(100,455	)	$	(61,594	)

_____________________

(a) The amendments that occurred during the twelve months ended December 31, 2010 primarily related to modifications to the required copayment levels, deductibles and out-of-pocket maximum responsibilities retained by the retired employees.

(b) 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,
	2011			2010
Net loss (gain)	$	20,144		$	(14,411	)
Prior service credit	(30,647		)	(36,574		)
	$	(10,503	)	$	(50,985	)

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

	December 31,
	2011		2010
Discount rate at end of year	4.3	%	5.5	%
Health care cost trend rates:
Initial	8.0	%	8.5	%
Ultimate	5.0	%	5.0	%
Year ultimate reached	2026		2018

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The discount rate is changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. A 1% increase in the discount rate would decrease the December 31, 2011 accumulated postretirement benefit obligation by 14.1%. A 1% decrease in the discount rate would increase the December 31, 2011 accumulated postretirement benefit obligation by 17.9%.

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

	Years Ended December 31,
	2011			2010			2009
Service cost	$	2,988		$	3,558		$	3,395
Interest cost	5,379			6,664			6,492
Expected return on plan assets	(1,823		)	(1,529		)	(1,499		)
Amortization of:
Prior service benefit	(5,927		)	(2,869		)	(2,869		)
Net gain	(39		)	(175		)	—
Net periodic benefit cost	$	578		$	5,649		$	5,519

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

	Years Ended December 31,
	2011		2010			2009
Net loss (gain)	$	34,517	$	(4,792	)	$	(1,843	)
Prior service benefit	—		(26,605		)	—
Amortization of:
Prior service benefit	5,927		2,869			2,869
Net gain	39		175			—
Total recognized in other comprehensive income	$	40,483	$	(28,353	)	$	1,026

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

	Years Ended December 31,
	2011		2010			2009
Total recognized in net periodic benefit cost and other comprehensive income	$	41,061	$	(22,704	)	$	6,545

The amounts in accumulated other comprehensive income that are expected to be recognized as a component of net periodic benefit cost during 2012 is a prior service benefit of $5.9 million and a net gain of $0.6 million.

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

	2011		2010		2009
Discount rate at beginning of year	5.5	%	5.9	%	6.0	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.9	%
Health care cost trend rates:
Initial	8.5	%	8.5	%	9.0	%
Ultimate	5.0	%	5.0	%	5.0	%
Year ultimate reached	2018		2017		2017

The discount rate is changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For measurement purposes, an 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease gradually to 5% for 2018 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, 2011 benefit obligation by $22.8 million or $18.3 million, respectively. In addition, such a 1% change would increase or decrease the aggregate 2011 service and interest cost components of the net periodic benefit cost by $1.6 million or $1.2 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2011. 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, 2011
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 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, 2011 and 2010, 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, 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
Description of Securities	Fair Value as of December 31, 2010		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	$	4,122	$	4,122	$	—	$	—
Municipal Securities – Tax Exempt	11,348		—		11,348		—
Common Stock	16,735		16,735		—		—
Limited Partnership Interest in Real Estate (a)	1,455		—		—		1,455
Total Plan Investments	$	33,660	$	20,857	$	11,348	$	1,455

 ___________________

(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 the investments in real estate during the period (in thousands):

	Fair Value of Investments  in Real Estate
Balance at December 31, 2009	$	1,554
Unrealized loss in fair value	(99		)
Balance at December 31, 2010	1,455
Sale of land	(19		)
Unrealized gain in fair value	160
Balance at December 31, 2011	$	1,596

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, 2011 and 2010.

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 mutual 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company expects to contribute $2.5 million to its other postretirement benefits plan in 2012. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

2012	$	3,519
2013	4,006
2014	4,507
2015	5,058
2016	5,614
2017-2021	35,367

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 2011, 2010 and 2009 were $1.7 million, $1.7 million, and $1.6 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. 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. In 2009, the Company reached the required levels of earnings per share, customer satisfaction, and safety goals for an incentive payment of $8.6 million, respectively. The Company has renewed the Incentive Plan in 2012 with similar goals.

N.     Franchises and Significant Customers

El Paso and Las Cruces Franchises

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

The franchise agreements 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

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 bases 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

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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,
	2011				2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	206,756	$	193,135	$	192,924
Senior Notes	546,662		700,371		546,610		574,700
RGRT Senior Notes (1)	110,000		116,985		110,000		110,371
RCF (1)	33,379		33,379		4,704		4,704
Total	$	883,176	$	1,057,491	$	854,449	$	882,699

 __________________

(1) Nuclear fuel financing as of December 31, 2011 is funded through the $110.0 million RGRT Senior Notes and $13.4 million under the RCF and $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 quarter 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 2012, 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, 2011, 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, 2011, 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 $168.0 million and $153.9 million at December 31, 2011 and 2010, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 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 (1):
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	)

 ____________________

(1) Includes approximately 96 securities.

	December 31, 2010
	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	$	2,290	$	(51	)	$	441	$	(27	)	$	2,731	$	(78	)
U.S. Government Bonds	9,583		(124		)	—		—			9,583		(124		)
Municipal Obligations	13,145		(278		)	3,763		(145		)	16,908		(423		)
Corporate Obligations	1,855		(18		)	—		—			1,855		(18		)
Total Debt Securities	26,873		(471		)	4,204		(172		)	31,077		(643		)
Common stock	6,943		(774		)	4,303		(420		)	11,246		(1,194		)
Total Temporarily Impaired Securities	$	33,816	$	(1,245	)	$	8,507	$	(592	)	$	42,323	$	(1,837	)

 ______________________

(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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	December 31, 2011				December 31, 2010
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	25,077	$	1,220	$	18,472	$	793
U.S. Government Bonds	10,263		972		10,450		183
Municipal Obligations	30,310		1,792		15,633		592
Corporate Obligations	7,641		459		7,223		362
Total Debt Securities	73,291		4,443		51,778		1,930
Common Stock	62,479		15,681		56,770		14,142
Cash and Cash Equivalents	3,739		—		3,007		—
Total	$	139,509	$	20,124	$	111,555	$	16,072

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 to 7 years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2011 is as follows (in thousands):

	Total		2012		2013 through 2016		2017 through 2021		2022 and Beyond
Municipal Debt Obligations	$	37,316	$	1,009	$	12,892	$	14,252	$	9,163
Corporate Debt Obligations	12,400		1,368		3,630		4,338		3,064
U.S. Government Bonds	12,776		1,316		1,685		6,844		2,931

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, 2011, 2010, and 2009 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2011			2010			2009
Gross unrealized holding losses included in pre-tax income	$	(2,116	)	$	(263	)	$	(5,594	)

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, 2011, 2010, and 2009 and the related effects on pre-tax income are as follows (in thousands):

	2011			2010			2009
Proceeds from sales of available-for-sale securities	$	82,926		$	61,656		$	79,935
Gross realized gains included in pre-tax income	$	1,479		$	1,030		$	3,614
Gross realized losses included in pre-tax income	(721		)	(889		)	(238		)
Gross unrealized losses included in pre-tax income	(2,116		)	(263		)	(5,594		)
Net losses in pre-tax income	$	(1,358	)	$	(122	)	$	(2,218	)
Net unrealized holding gains included in accumulated other comprehensive income	$	1,570		$	6,665		$	12,816
Net losses reclassified out of accumulated other comprehensive income	1,358			122			2,218
Net gains in other comprehensive income	$	2,928		$	6,787		$	15,034

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Investment in Debt Securities. As of December 31, 2011, the Company had a $2.0 million investment in an auction rate security maturing in 2044. The Company classifies this debt security as a trading security which is included in deferred charges and other assets on the Company’s consolidated balance sheets.

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 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, 2011 and 2010, 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, 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	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Description of Securities	Fair Value as  of December 31, 2010		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	$	2,909	$	—	$	—	$	2,909
Available for sale:
U.S. Government Bonds	$	20,033	$	20,033	$	—	$	—
Federal Agency Mortgage Backed Securities	21,204		—		21,204		—
Municipal Bonds	32,541		—		32,541		—
Corporate Asset Backed Obligations	9,077		—		9,077		—
Subtotal, Debt Securities	82,855		20,033		62,822		—
Common Stock	68,016		68,016		—		—
Cash and Cash Equivalents	3,007		3,007		—		—
Total available for sale	$	153,878	$	91,056	$	62,822	$	—

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

	2011			2010
Balance at January 1	$	2,909		$	2,510
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)	(220		)	399
Balance at December 31	$	1,120		$	2,909

_____________________

(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, 2011 and 2010. 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, 2011 and 2010.

P.    Supplemental Statements of Cash Flows Disclosures

	Years Ended December 31,
	2011			2010		2009
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	48,664		$	47,783	$	46,836
Income taxes paid (refund), net	(6,260		)	7,343		8,596
Non-cash financing activities:
Grants of restricted shares of common stock	3,268			2,098		1,592
Issuance of performance shares	628			663		—
Acquisition of treasury stock for options exercised	500			—		—

98

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.

	2011 Quarters								2010 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	191,663	$	307,633	$	242,605	$	176,112	$	181,344	$	280,342	$	211,397	$	204,168
Operating income	15,994		102,215		58,121		14,473		13,784		84,098		40,477		30,603
Income before extraordinary gain	5,453		58,321		32,990		6,775		7,466		49,896		21,507		11,449
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		10,286		—		—
Net income	5,453		58,321		32,990		6,775		7,466		60,182		21,507		11,449
Basic earnings per share:
Income before extraordinary gain	0.14		1.41		0.78		0.16		0.18		1.16		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.14		1.41		0.78		0.16		0.18		1.40		0.49		0.26
Diluted earnings per share:
Income before extraordinary gain	0.13		1.40		0.78		0.16		0.17		1.15		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.13		1.40		0.78		0.16		0.17		1.39		0.49		0.26
Dividends declared per share of common stock	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.

99

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, 2011, 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 45 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, 2011, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

100

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 2012 Annual Meeting of Shareholders (the “2012 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 2012 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 2012 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 2012 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 2012 Proxy Statement under the caption “Business Conduct Policies” under the heading “Corporate Governance.”

Item 11. Executive Compensation

Incorporated herein by reference from the 2012 Proxy Statement under the heading “Summary of Compensation.”

Item 12. Security Ownership of Certain Beneficial Management

Incorporated herein by reference from the 2012 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	47,336	$	12.80	453,358
Equity compensation plans
not approved by security holders	—	—		—
Total	47,336	$	12.80	453,358

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

Incorporated herein by reference from the 2012 Proxy Statement under the heading “Certain Relationships and Related Party Transactions.”

Item 14. Principal Accounting Fees and Services

Incorporated herein by reference from the 2012 Proxy Statement under the heading “Independent Registered Public Accounting Firm.”

101

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	46
2.	Financial Statement Schedules:
	All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.
3.	Exhibits

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.

102

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 July 1, 2005 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2005 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.30 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.04	–	Loan Agreement dated July 1, 2005 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 4.31 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.05	–	Representation and Indemnity Agreement dated July 27, 2005 among El Paso Electric Company, Citigroup Global Markets Inc., BNY Capital Markets, Inc., J.P. Morgan Securities Inc., and the Maricopa County, Arizona Pollution Control Corporation, relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.32 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.06	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $63,500,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.07	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.06. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.08	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series B (El Paso Electric Company Palo Verde Project). (Exhibit 4.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.09	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.08. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.10	–	Remarketing Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.37 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.11	–	Tender Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.38 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

103

Exhibit Number		Title
	4.12	–	Reserved
	4.13	–	Reserved
	4.14	–	Reserved
	4.15	–	Remarketing and Purchase Agreement dated July 27, 2005 among El Paso Electric Company and Citigroup Global Markets Inc., as remarketing agent, and Citigroup Global Markets Inc., BNY Capital Markets, Inc., and J.P. Morgan Securities Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.42 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.16	–	Tender Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.43 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.17	–	Remarketing Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.18. (Exhibit 4.44 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)
	4.18	–	Ordinance No. 2002-1134 adopted by the City Council of Farmington, New Mexico on July 9, 2002 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 principal amount of its Pollution Control Revenue Refunding Bonds, 2002 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.22 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
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)
	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)
	10.06	–	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)

104

	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.
	10.15	–	Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
	10.16	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
	10.17	–	Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	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)

105

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.
†10.26		–	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		–	Form of Directors’ Stock Option Agreement between the Company and certain directors of the Company. (Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
	10.31	–	El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)
	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)

106

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	–	Rate Agreement between the Company and the City of El Paso, Texas, dated as of July 1, 2005. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the year ended June 30, 2005)
	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)
†††††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).
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 113 of this report)
Exhibit 24 – Power of Attorney:

107

*24.01		–	Power of Attorney (set forth on page 111 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
	*		Filed herewith.
	†		Fourteen agreements, substantially identical in all material respects to this exhibit, have been entered into with David W. Stevens; David G. Carpenter; Steven P. Busser; Steven T. Buraczyk; Robert C. Doyle; Richard G. Fleager; Nathan T. Hirschi; Mary E. Kipp; Kerry B. Lore; Rocky R. Miracle; Hector R. Puente; Andres R. Ramirez; Guillermo Silva, Jr.; and John A. Whitacre; officers of the Company.
	††		One agreement, dated as of July 15, 2002, identical in all material respects to this Exhibit, has been entered into with John A. Whitacre; officer 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, 2010, April 1, 2010, July 1, 2010 and October 1, 2010, 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 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, eleven agreements, dated as of May 26, 2010, 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.

108

	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, two agreements, dated as of July 1, 2002 and October 1, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; director of the Company.
	In lieu of non-employee director cash compensation, two agreements, dated as of January 1, 2003 and April 1, 2003, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; director 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.

109

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.

110

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 David W. Stevens, 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.

111

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 24th day of February 2012.

EL PASO ELECTRIC COMPANY
By:	/s/ DAVID W. STEVENS
	David W. Stevens
	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/ DAVID W. STEVENS	Chief Executive Officer (Principal Executive Officer)	February 24, 2012
(David W. Stevens)
/s/ DAVID G. CARPENTER	Senior Vice President and Chief Financial Officer (Principal Financial Officer )	February 24, 2012
(David G. Carpenter)
/s/ NATHAN T. HIRSCHI	Vice President and Controller	February 24, 2012
(Nathan T. Hirschi)
/s/ CATHERINE A. ALLEN	Director	February 24, 2012
(Catherine A. Allen)
/s/ J. ROBERT BROWN	Director	February 24, 2012
(J. Robert Brown)
/s/ JAMES W. CICCONI	Director	February 24, 2012
(James W. Cicconi)
/s/ JAMES W. HARRIS	Director	February 24, 2012
(James W. Harris)
/s/ KENNETH R. HEITZ	Director	February 24, 2012
(Kenneth R. Heitz)
/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 24, 2012
(Patricia Z. Holland-Branch)
/s/ MICHAEL K. PARKS	Director	February 24, 2012
(Michael K. Parks)
/s/ THOMAS V. SHOCKLEY	Director	February 24, 2012
(Thomas V. Shockley)
/s/ ERIC B. SIEGEL	Director	February 24, 2012
(Eric B. Siegel)
/s/ STEPHEN N. WERTHEIMER	Director	February 24, 2012
(Stephen N. Wertheimer)
/s/ CHARLES A. YAMARONE	Director	February 24, 2012
(Charles A. Yamarone)

112

EX-10.14-01

Exhibit 10.14-01

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

El Paso Electric Company)

v.)Docket No. EL06-45-000 and all sub-dockets

Tucson Electric Power Company)

Tucson Electric Power Company)

v.)Docket No. EL06-46-000 and all sub-dockets

El Paso Electric Company)

[Consolidated]

SETTLEMENT AGREEMENT

This Settlement Agreement (“Settlement”) is by and between El Paso Electric Company (“El Paso”) and Tucson Electric Power Company (“Tucson”) in resolution of their disputes regarding the “Tucson - El Paso Power Exchange and Transmission Agreement” entered into in 1982 (“the 1982 Agreement”), which disputes have been the subject of the complaint dockets identified above, currently pending on appeal before the United States Court of Appeals for the District of Columbia Circuit, and also the subject of litigation before the United States District Court for the District of Arizona. El Paso and Tucson are sometimes referred to jointly as the “Parties.”

WHEREAS, El Paso and Tucson have worked together over the course of the last several months in an effort to resolve their differences under the 1982 Agreement;

WHEREAS, those efforts have resulted in a mutually-agreed upon resolution that will end the

litigation that commenced five years ago before the Federal Energy Regulatory Commission (the “Commission”), and now is the subject of two related cases before the Courts;

WHEREAS, the Parties look forward to working with each other cooperatively during the many years to come under which this Settlement is to remain in effect.

ACCORDINGLY, EL PASO AND TUCSON HAVE AGREED, AS FOLLOWS:

ARTICLE I

TUCSON LUMP SUM PAYMENT TO EL PASO

Within 10 calendar days from the Settlement's Effective Date, Tucson shall pay El Paso, by check or wire transfer, a lump sum amount equal to the total amount that would have been paid if Tucson had paid El Paso $69,300 per month from February 1, 2006 through the day immediately prior to the Settlement's Effective Date, plus interest calculated in accordance with the methodology set forth in 18 CFR § 35.19a(2)(iii), for the period from February 1, 2006 to the Effective Date. The Parties agree that the amount will be calculated as shown in the attachment, which sets forth the amount calculated for the period February 1, 2006 through year-end 2010. This amount will continue to accrue principal and interest until the Effective Date. This payment under Article I is an integral part of the Settlement's overall resolution of the Parties' claims against each other related to Tucson's rights to transmission service on the El Paso system in the Springerville-Luna 345 kV circuit and in the 345 kV circuit from Luna via Hidalgo to Greenlee under the 1982 Agreement.

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ARTICLE II

TUCSON'S RESERVATION OF OATT SERVICE FROM EL PASO

Immediately upon the Settlement's Effective Date and continuing through the term of the Settlement (unless otherwise mutually agreed upon by the Parties), Tucson shall reserve from El Paso at least 30 MW of firm point-to-point transmission capacity under the Open Access Transmission Tariff of El Paso on file at the Commission (“El Paso's OATT”) for transmission of electricity from the receipt point of Luna to the delivery point of Greenlee, under the attached service agreement, and shall pay for such capacity at the yearly delivery rate for firm point-to-point transmission service set forth in Schedule 7, Section A, of El Paso's OATT (as that rate may change from time to time).

In addition, immediately upon the later of the Settlement's Effective Date and the date on which Tucson (or any party delivering power to Tucson's Balancing Authority Area for Tucson's use in serving its load) begins receiving electricity from the first phase of the Macho Springs Project, and continuing through the term of the Settlement (unless otherwise mutually agreed upon by the Parties), Tucson shall reserve from El Paso at least 10 MW of firm point-to-point transmission capacity under El Paso's OATT for transmission of electricity from the receipt point of Luna to the delivery point of Springerville under the attached service agreement, and shall pay for such capacity at the yearly delivery rate for firm point-to-point transmission service set forth in Schedule 7, Section A of El Paso's OATT (as that rate may change from time to time). The Macho Springs Project refers to the 99 MW generating facility being constructed by Macho Springs Power I, LLC in Luna County, New Mexico to interconnect with the El Paso

3

system approximately 30 miles from the receipt point of Luna. The first phase of the Macho Springs Project consists of approximately 50 MW.

To be clear, in no circumstance during the term of this Settlement will the rate Tucson pays El Paso for firm point-to-point service under this Article be less than the El Paso Schedule 7, Section A yearly delivery rate currently set forth in El Paso's OATT, unless El Paso makes a rate change filing to lower its rates for Schedule 7, Section A service under Section 205 of the Federal Power Act, or the Commission or a third party seeks to lower El Paso's rates for Schedule 7, Section A service pursuant to Section 206 of the Federal Power Act, and those lower rates are made effective during the term of this Settlement.

Tucson may request El Paso to provide transmission service on a non-firm basis over receipt points and delivery points other than those specified in the attached service agreements, in amounts not to exceed its firm capacity reservations, without incurring an additional non-firm point-to-point transmission service charge or executing a new service agreement, subject to the conditions specified in Section 22.1 of the El Paso OATT. Tucson may also request El Paso to modify the receipt points and/or delivery points specified in the attached service agreements on a firm basis in accordance with Section 22.2 of the El Paso OATT. If Tucson requests modification of receipt or delivery points on a firm basis under Section 22.2 of El Paso's OATT, El Paso shall treat the request as a new request for service, and process it under the procedures set forth in El Paso's OATT. Unless the receipt points and/or delivery points specified in the attached service agreements are modified on a firm basis, Tucson shall remain obligated to reserve, and pay for, at least 30 MW and 10 MW of firm point-to-point transmission capacity at the points set forth in the attached service agreements

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through the term of the Settlement. If the receipt points and/or delivery points specified in the attached service agreements are modified on a firm basis during the term of the Settlement, Tucson shall remain obligated to reserve, and pay for, at least 30 MW and 10 MW of firm point-to-point transmission capacity at the modified points, at a rate no less than El Paso's Schedule 7, Section A yearly delivery rate.

Tucson shall be responsible for compensating El Paso for real power losses pursuant to Schedule 10 of the El Paso OATT, as that schedule may change from time to time. Tucson shall also be responsible for paying any applicable ancillary service charges (including, but not limited to charges for ancillary services under Schedules 1 and 2 of El Paso's OATT), and any other charges (in effect currently or made effective during the term of this Settlement) applicable under El Paso's OATT to firm point-to-point transmission service provided pursuant to the attached service agreements or any superseding service agreements.

Nothing in this Settlement shall affect Tucson's right to contest any rate change filing under El Paso's OATT that may be proposed by El Paso during the term of this Settlement, including any filing that proposes a change to (a) the rates for firm point-to-point transmission service set forth in El Paso's OATT, (b) the amount of compensation to be provided by Tucson for real power losses or the manner in which that compensation is to be provided, or (c) any ancillary service charges applicable to firm point-to-point transmission service.

ARTICLE III

TRANSMISSION RIGHTS UNDER THE 1982 AGREEMENT

170 MW of Transmission. Upon the Effective Date of the Settlement, the 200 MW of transmission rights assigned by El Paso to Tucson in the Springerville-Luna 345 kV circuit and in

5

the 345 kV circuit from Luna via Hidalgo to Greenlee in Sections 6.3 and 6.4 of the 1982 Agreement shall be reduced to 170 MW of transmission rights, and to only the following eligible point combinations, in the direction shown:

345 kV Receipt Point345 kV Delivery Point

SpringervilleàGreenlee

Macho SpringsàSpringerville

Macho SpringsàGreenlee

LunaàSpringerville

LunaàGreenlee

Tucson shall be deemed to have reserved 170 MW on each circuit (the Springerville-Luna 345 kV circuit and the 345 kV circuit from Luna via Hidalgo to Greenlee), but Tucson may not schedule more than 170 MW of transmission service on these lines under the 1982 Agreement, in total, at any one time. For example, if Tucson were to schedule 130 MW of transmission service under the 1982 Agreement from any receipt point designated above to the corresponding delivery point, it could only schedule a maximum of 40 MW of additional transmission service under the 1982 Agreement between any receipt point and any corresponding delivery point listed above for delivery at the same time. El Paso will not accept multiple schedules of transmission service from Tucson where such schedules provide for simultaneous transmission of electricity under the 1982 Agreement in excess of 170 MW, in total. For example, if Tucson were to schedule 170 MW from Macho Springs to Springerville under the 1982 Agreement, it would not be able to schedule transmission service for delivery of electricity from Luna to Greenlee, at the same time under the 1982 Agreement. In addition, the total amount of electricity to be transmitted at any time under the 1982 Agreement in

6

accordance with Article III, and on a firm or non-firm basis under El Paso's OATT in accordance with Article II, for delivery to Greenlee is subject to a maximum limit of 200 MW. See Article IV.

No Other Points Permitted. To repeat what is prescribed above, Tucson's 170 MW of transmission rights under the 1982 Agreement shall be solely at the receipt and delivery points identified above, and solely in the point combinations and directions shown. No other points, point combinations or directions are permitted.

Ancillary Services. The Parties understand and agree that transmission service provided by each Party under the 1982 Agreement is a “bundled” service which includes both transmission service and certain transmission support functions that are needed for the reliable transmission of electricity, and that nothing in FERC Order No. 888 or any other FERC rule, regulation or order has required this service to be “unbundled.” The Parties further agree that:

a) Each of the Parties shall continue to provide such bundled transmission service whenever it transmits electricity for the other Party under the 1982 Agreement, in the same manner in which it has provided bundled transmission service in past years under the 1982 Agreement.

b) In the event transmission service under the 1982 Agreement is required to be “unbundled” but the 1982 Agreement otherwise remains intact, the transmitting Party shall provide scheduling, system control and dispatch service; reactive supply and voltage control from generation or other sources service; and real power losses (as those services are defined in FERC Order No. 888), as unbundled ancillary services in conjunction with the transmission of electricity under the 1982 Agreement. Charges for real power losses will be those specified in the 1982

7

Agreement, and each of the other two services will be provided at no additional charge to the Party for whom electricity is being transmitted. However, the transmitting Party shall not be obligated to provide any other ancillary services (including those ancillary services specified in FERC Order No. 888 or any ancillary services defined by the FERC in the future) in conjunction with transmission of electricity under the 1982 Agreement.

c) In the event that transmission service under the 1982 Agreement is required to be unbundled, the Party for whom electricity is being transmitted shall have no obligation either to purchase any ancillary services from the transmitting Party or to self-provide any ancillary services as a condition of having electricity transmitted under the 1982 Agreement.

Macho Springs Receipts. Macho Springs is a receipt point not currently in existence, but it may become a receipt point during the term of this Settlement upon the interconnection to the El Paso system of the generating facility being constructed by Macho Springs Power I, LLC in Luna County, New Mexico. The Parties specifically agree as part of this Settlement that (a) the only power eligible for receipt at the Macho Springs point for transmission under the 1982 Agreement is power generated by the Macho Springs Project; and (b) any time Tucson schedules transmission service on the El Paso transmission system with Macho Springs as a receipt point (whether under the OATT service agreements entered into under Article II or under the 1982 Agreement under this Article III), Tucson shall dynamically transfer its Macho Springs power out of El Paso's Balancing Authority Area. In the event transmission service under the 1982 Agreement is required to be unbundled, El Paso shall not be obligated by the

8

1982 Agreement or this Settlement to offer and/or provide, in association with any power received at the Macho Springs point, regulation service, energy imbalance service, generator imbalance service, or any other ancillary service adopted by FERC in the future.

To the extent that other ancillary services are necessary or required for the transmission of power generated by the Macho Springs Project under the 1982 Agreement and this Settlement, El Paso shall not be responsible for those other ancillary services, unless otherwise mutually-agreed between Tucson and El Paso.

El Paso Generator Receipts. El Paso may desire to use transmission rights that were assigned to it in the 1982 Agreement for transmission of electricity generated by a new wind-powered or other renewable generator that may be interconnected to the Tucson system in the future (the “El Paso Generator”). The Parties specifically agree as part of this Settlement that (a) any time El Paso schedules transmission service under the 1982 Agreement with the El Paso Generator as a receipt point, El Paso must dynamically transfer its power from the El Paso Generator out of Tucson's Balancing Authority Area, and (b) the only power eligible for receipt at the El Paso Generator receipt point under the 1982 Agreement is power from the El Paso Generator. In the event transmission service under the 1982 Agreement is required to be unbundled, Tucson is not obligated by the 1982 Agreement or this Settlement to offer and/or provide in association with any power received at the El Paso Generator receipt point, regulation service, energy imbalance service, generator imbalance service or any other ancillary service adopted by FERC in the future.

To the extent that other ancillary services are necessary or required for the transmission of power generated by the El Paso Generator under the 1982 Agreement and this Settlement,

9

Tucson shall not be responsible for those other ancillary services, unless otherwise mutually-agreed between Tucson and El Paso.

New Generation. This Settlement does not require either Party to construct facilities for the other Party's benefit under the 1982 Agreement. Tucson has indicated to El Paso that it may desire to add new generation in the future at the Luna or Springerville receipt points, and the Parties hereby agree as follows:

(a) If Tucson (or its affiliate) constructs a new generation plant at either Luna or Springerville during the term of this Settlement, Tucson shall:

(i) request interconnection under the Large or Small Generator Interconnection Procedures in El Paso's OATT, and pre-pay for the cost of all facilities, including Network Upgrades, required for the interconnection, and

(ii) at Tucson's election, Tucson shall either (a) purchase and pay for transmission service for delivery of electricity generated by such generation under El Paso's OATT (with any associated obligation imposed on Tucson under El Paso's OATT to pay El Paso for transmission facilities necessary to provide the OATT service), or (b) make El Paso whole for the full cost of any facilities required to be constructed and/or installed for the interconnection, including Network Upgrade costs (if Tucson elects to have such generation transmitted under the 1982 Agreement).

10

(b) If Tucson elects to have such electricity from the new generation plant transmitted under the 1982 Agreement, the method under which Tucson shall make El Paso whole shall be as follows: El Paso shall (i) calculate the non-usage portion of transmission charges paid by all transmission customers for transmission services under El Paso's OATT associated with the new generation at the end of the repayment period agreed to by El Paso under the Large or Small Generator Interconnection Agreement under which the new generation plant was interconnected, with respect to power from the new generation plant, and (ii) reimburse Tucson this amount; provided, however, that El Paso shall not be obligated to reimburse Tucson any more than an amount equal to the total Network Upgrade costs associated with the interconnection.

(c) If, instead of constructing a new generation plant at either Luna or Springerville, Tucson purchases power from new generation constructed by an unaffiliated third party at Luna and Springerville, Tucson shall, at its election, either (i) have electricity from such new generation plant transmitted under El Paso's OATT (with any associated obligation imposed on Tucson under the OATT to pay El Paso for transmission facilities necessary to provide the OATT service), or (ii) make El Paso whole for the cost of Network Upgrades associated with the interconnection (if Tucson elects to have electricity from such new generation plant transmitted under the 1982 Agreement).

(d) If Tucson elects to have electricity from such new generation plant transmitted under the 1982 Agreement, the method under which Tucson shall make El Paso whole shall be as follows: El Paso shall (i) calculate the non-usage portion of transmission charges paid by all transmission customers for transmission services under El Paso's OATT associated with the new

11

generation at the end of the repayment period agreed to by El Paso under the Large or Small Generator Interconnection Agreement under which the new generation plant was interconnected, with respect to power from the new generation plant, (ii) subtract those charges from the Network Upgrade costs (including interest) for which El Paso has a reimbursement obligation to the generator under the Large or Small Generator Interconnection Agreement, and (iii) invoice Tucson the difference. Tucson shall pay the invoice within 30 days.

(e) When El Paso transmits electricity from any new generation plant at Luna or Springerville for delivery to Tucson under the 1982 Agreement in accordance with the provisions set forth above, Tucson shall dynamically transfer such generation out of El Paso's Balancing Authority Area and El Paso's obligation to offer and/or provide ancillary services for the new generation added at Luna or Springerville shall be no greater than that applicable to the receipt of power at the Macho Springs receipt point under the Section of this Article III entitled “Macho Springs Receipts.”

(f) If El Paso's Large or Small Generator Interconnection Procedures or form of agreement change during the period this Settlement is in effect such that there is an inconsistency between the full pre-payment obligation imposed upon Tucson in subsection (a)(i) above and the pre-payment provisions in the revised procedures, then the pre-payment provisions in this Settlement shall govern.

(g) Similarly, if El Paso constructs a new generation plant during the term of this Settlement at points of receipt connected to transmission facilities owned by Tucson in which El Paso has been assigned transmission rights under the 1982 Agreement, El Paso shall:

12

(i) request interconnection under the Large or Small Generator Interconnection Procedures in Tucson's OATT, and pre-pay for the cost of all facilities, including Network Upgrades, required for the interconnection,

and

(ii) at El Paso's election, El Paso shall either (a) purchase and pay for transmission service for delivery of electricity generated by such generation under Tucson's OATT (with any associated obligation imposed on El Paso under Tucson's OATT to pay Tucson for transmission facilities necessary to provide the OATT service), or (b) make Tucson whole for the full cost of any facilities required to be constructed and/or installed for the interconnection, including Network Upgrade costs (if El Paso elects to have such generation transmitted under the 1982 Agreement).

(h) If El Paso elects to have such electricity from the new generation plant transmitted under the 1982 Agreement, the method under which El Paso shall make Tucson whole shall be as follows: Tucson shall (i) calculate the non-usage portion of transmission charges paid by all transmission customers for transmission services under Tucson's OATT associated with the new generation at the end of the repayment period agreed to by Tucson under the Large or Small Generator Interconnection Agreement under which the new generation plant was interconnected, with respect to power from the new generation plant, and (ii) reimburse El Paso this amount; provided, however, that Tucson shall not be obligated to reimburse El Paso any more than an amount equal to the total Network Upgrade costs associated with the interconnection.

13

(i) If, instead of constructing a new generation plant, El Paso purchases power from new generation constructed by an unaffiliated third party, El Paso shall, at its election, either (i) have electricity from such new generation plant transmitted under Tucson's OATT (with any associated obligation imposed on El Paso under the OATT to pay Tucson for transmission facilities necessary to provide the OATT service), or (ii) make Tucson whole for the cost of Network Upgrades associated with the interconnection (if El Paso elects to have electricity from such new generation plant transmitted under the 1982 Agreement).

(j) If El Paso elects to have electricity from such new generation plant transmitted under the 1982 Agreement, the method under which El Paso shall make Tucson whole shall be as follows: Tucson shall (i) calculate the non-usage portion of transmission charges paid by all transmission customers for transmission services under Tucson's OATT associated with the new generation at the end of the repayment period agreed to by Tucson under the Large or Small Generator Interconnection Agreement under which the new generation plant was interconnected, with respect to power from the new generation plant, (ii) subtract those charges from the Network Upgrade costs (including interest) for which Tucson has a reimbursement obligation to the generator under the Large or Small Generator Interconnection Agreement, and (iii) invoice El Paso the difference. El Paso shall pay the invoice within 30 days.

(k) When Tucson transmits electricity from any new generation plant for delivery to El Paso under the 1982 Agreement in accordance with the provisions set forth above, El Paso shall dynamically transfer such generation out of Tucson's Balancing Authority Area and Tucson's obligation to offer and/or provide ancillary services for the new generation added shall be no

14

greater than that applicable to the receipt of power at the Macho Springs receipt point under the Section of this Article III entitled “Macho Springs Receipts.”

(l) If Tucson's Large or Small Generator Interconnection Procedures or form of agreement change during the period this Settlement is in effect such that there is an inconsistency between the full pre-payment obligation imposed upon El Paso in subsection (g)(i) above and the pre-payment provisions in the revised procedures, then the pre-payment provisions in this Settlement shall govern.

ARTICLE IV

GREENLEE

Service provided under Articles II and III of this Settlement, combined, shall not exceed 200 MW for delivery at Greenlee at any time.

ARTICLE V

EFFECTIVE DATE AND TERM

Effective Date. The Effective Date of this Settlement is the first day of the first month after the later to occur of the following two issuances: (a) issuance by the Federal Energy Regulatory Commission of a Final Non-Appealable Order approving the Settlement without modification or condition, and (b) issuance by the Federal Energy Regulatory Commission of a Final Non-Appealable Order approving a settlement agreement between El Paso and Macho Springs Power I, LLC regarding the reimbursement of network upgrade costs associated with the interconnection of Macho Springs to the El Paso system. To be clear, both issuances must occur for the Settlement to become effective.

Final Non-Appealable Order. An order shall be considered a Final Non-Appealable Order (i) on the day after the expiration of the period for filing a request for rehearing of the

15

Commission's order approving the Settlement, when no such request for rehearing has been filed, or (ii) if a request for rehearing is filed, on the day after the expiration of the period for filing a request for rehearing of the Commission's order on rehearing, when no further request for rehearing is filed. Neither El Paso nor Tucson will file a request for rehearing of a Commission order approving the Settlement without modification or condition.

Term. This Settlement shall become effective on the Effective Date and remain in effect for the remaining term set forth in Section 6.4 of the 1982 Agreement, which term began with the commercial operation date of the Luna-Springerville circuit (on April 19, 1990) and is to end 40 years later (on April 19, 2030).

ARTICLE VI

FINAL RESOLUTION AND WAIVER

Final Resolution. This Settlement shall be a final and complete resolution of Tucson's rights to transmission service on the El Paso system in the Springerville-Luna 345 kV circuit and in the 345 kV circuit from Luna via Hidalgo to Greenlee under the 1982 Agreement.

Litigation Withdrawn. Within 10 calendar days of the Settlement's Effective Date, El Paso shall withdraw its appeal before the United States Court of Appeals for the District of Columbia Circuit in Case No. 10-1194, and Tucson shall withdraw its complaint before the United States District Court for the District of Arizona in Case No. 4:08-CV-680-TUC-CKJ. The Parties agree to not re-file or otherwise pursue those claims, or the claims in underlying proceedings, in the future.

16

Waiver. Approval of this Settlement shall constitute waiver of any of the Commission's rules and regulations that may be necessary to effectuate the Settlement in accordance with all of its terms.

ARTICLE VII

MISCELLANEOUS

Standard of Review. It is the intent of the Parties that, to the maximum extent permitted by law, the provisions of this Settlement shall not be subject to change under Sections 205 and 206 absent the written agreement of the Parties, and that the standard of review for changes unilaterally proposed by either El Paso or Tucson, or by the Commission acting sua sponte or at the request of a third party, shall be the public interest standard of review, sometimes referred to as the Mobile Sierra public interest standard.

Compromise. This Settlement is a compromise for the purpose of reaching a resolution of a long-standing dispute. The Commission's approval of the Settlement shall not constitute approval of, or any precedent regarding, any principle or issue or methodology underlying the Settlement.

No Precedent. This Settlement is entered into upon the understanding that it constitutes a negotiated agreement and no Party shall be deemed to have approved, accepted, agreed to, or consented to any principle or position in the captioned proceedings or to have prejudiced positions taken or that may be taken in these or any other proceedings. This Settlement shall not be cited or relied upon as precedent for any purpose, or as establishing any issue or principle, except to the extent of enforcing the terms and conditions of the Settlement itself. Nothing herein shall be deemed a “settled practice” as that term was

17

interpreted and applied in Public Service Comm'n of New York v. FERC, 642 F.2d 1335 (D.C. Cir. 1980).

Withdrawal. This Settlement is submitted by the Parties on the express condition that it will not become effective if the Commission modifies and/or attaches conditions to it. In the event the Settlement does not become effective pursuant to its terms, it will be withdrawn from the dockets and shall not be used by anyone in these Commission proceedings or in any other case, court docket or other forum.

Nonseverability. The Settlement's various provisions are not severable.

Governing Law, Regulatory Authority, and Rules. The validity, interpretation and enforcement of this Settlement and each of its provisions shall be governed and construed in accordance with the laws of the State of Arizona, without regard to its conflicts of law principles; provided, however, that where jurisdiction over a dispute between the Parties properly lies before the federal courts, the Party with a cause of action may file suit before a federal court with jurisdiction to hear the dispute. This Settlement is subject to all Applicable Laws and Regulations. Each Party expressly reserves the right to seek changes in, appeal, or otherwise contest any laws, orders, or regulations of a Governmental Authority.

Amendment. The Parties may amend this Settlement by a written instrument duly executed by both Parties, subject to any applicable approval(s) required by a Governmental Authority.

No Third-Party Beneficiaries. This Settlement is not intended to and does not create rights, remedies, or benefits of any character whatsoever in favor of any persons, corporations, associations, or entities other than the Parties, and the obligations herein assumed are solely

18

for the use and benefit of the Parties. Neither Party may assign the rights provided it under this Settlement.

Waiver. The failure of a Party to this Settlement to insist, on any occasion, upon strict performance of any provision of this Settlement will not be considered a waiver of any obligation, right, or duty of, or imposed upon, such Party. Any waiver at any time by either Party of its rights with respect to this Settlement shall not be deemed a continuing waiver or a waiver with respect to any other failure to comply with any other obligation, right, duty of this Settlement. Any waiver of this Settlement shall, if requested, be provided in writing.

Entire Agreement. This Settlement, including all attachments and any documents identified there, constitutes the entire agreement between the Parties with reference to the subject matter hereof, and supersedes all prior and contemporaneous understandings or agreements, oral or written, between the Parties with respect to the subject matter of this Settlement.

Conflicts. In the event of a conflict between the body of this Settlement and any attachments, the terms and provisions of the body of this Settlement shall prevail and be deemed the final intent of the Parties.

No Dedication of Facilities. No undertaking by El Paso under any provision of this Settlement shall constitute the dedication of El Paso's system or any portion thereof to Tucson or to the public.

Partnership. This Settlement shall not be interpreted or construed to create an association, joint venture, agency relationship, or partnership between the Parties or to impose any partnership obligation or partnership liability upon either Party. Neither Party shall have

19

any right, power or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party.

Notices. Notices required in connection with the scheduling of transmission service under Article II of this Settlement shall be in accordance with the service agreements attached to the Settlement. Notices required in connection with the scheduling of transmission service under Article III of this Settlement shall be in conformance with the Parties past practices under the 1982 Agreement. Any other written notice or request of a more general nature in connection with this Settlement shall be tendered to the applicable Party at the following addresses:

If to Tucson:

Tucson Electric Power Company

c/o UniSource Energy Corp.

Attention: General Counsel    

One South Church Avenue

Tucson, AZ 85701

Phone:     

Fax:         

Email:     

If to El Paso:

El Paso Electric Company         El Paso Electric Company

Attention: General Counsel      Attention: Asst. VP - System Operations

100 N. Stanton             100 N. Stanton

El Paso, TX 79901            El Paso, TX 79901

Phone: (915) 543-5776         Phone: (915) 543-5719

Fax: (915) 521-4728            Fax: (915) 521-4763

Email: mary.kipp@epelectric.com     Email: joe.nevarez@epelectric.com

Interpretation. Both Parties participated in the preparation of this Settlement and no ambiguity should be construed against any Party as the primary drafter hereof.

20

Privilege for Settlement Discussion. All offers of settlement and settlement discussions and negotiations related thereto are and shall remain subject to the privilege for such communications established by the Commission's Rules.

Multiple Counterparts. This Settlement may be executed in two or more counterparts, each of which is deemed an original but all constitute one and the same instrument.

The Parties have caused their duly authorized representatives to execute this Settlement on this 26th day of April, 2011.

For El Paso Electric CompanyFor Tucson Electric Power Company

/s/David W. Stevens /s/David G. Hutchens

Print Name: David W. StevensPrint Name: David G. Hutchens

Title: April 26, 2011Title: Executive Vice President

21

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0678		0.0730		0.0774		0.0817		0.0825		0.0825		0.0825
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		31-Mar-06		30-Jun-06		30-Sep-06		31-Dec-06		31-Mar-07		30-Jun-07		30-Sep-07
	$2.31 kW/mo.	Assume	90 Days In Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter		90 Days In Quarter		91 Days in Quarter		92 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative
			0.0170	Balance	0.0183	Balance	0.0194	Balance	0.0204	Balance	0.0206	Balance	0.0206	Balance	0.0206	Balance
			Q1 2006	Q1 2006	Q2 2006	Q2 2006	Q3 2006	Q3 2006	Q4 2006	Q4 2006	Q1 2007	Q1 2007	Q2 2007	Q2 2007	Q3 2007	Q3 2007
Feb 06	69,300	1-Feb-06	757	70,057	1,279	71,336	1,380	72,716	1,485	74,201	1,530	75,731	1,562	77,293	1,594	78,888
Mar	69,300	1-Mar-06	392	69,692	1,272	70,963	1,373	72,337	1,477	73,814	1,522	75,336	1,554	76,890	1,586	78,476
Apr	69,300	1-Apr-06	—	—	1,251	70,551	1,365	71,916	1,469	73,385	1,514	74,898	1,545	76,443	1,577	78,020
May	69,300	1-May-06	—	—	834	70,134	1,357	71,491	1,460	72,951	1,505	74,456	1,536	75,991	1,567	77,559
Jun	69,300	1-Jun-06	—	—	403	69,703	1,349	71,052	1,451	72,503	1,495	73,998	1,526	75,525	1,558	77,082
Jul	69,300	1-Jul-06	—	—	—	—	1,326	70,626	1,443	72,069	1,486	73,555	1,517	75,072	1,548	76,621
Aug	69,300	1-Aug-06	—	—	—	—	875	70,175	1,433	71,608	1,477	73,085	1,507	74,592	1,538	76,131
Sep	69,300	1-Sep-06	—	—	—	—	423	69,723	1,424	71,147	1,467	72,614	1,498	74,112	1,529	75,640
Oct	69,300	1-Oct-06	—	—	—	—	—	—	1,400	70,700	1,458	72,158	1,488	73,647	1,519	75,165
Nov	69,300	1-Nov-06	—	—	—	—	—	—	923	70,223	1,448	71,671	1,478	73,150	1,509	74,658
Dec	69,300	1-Dec-06	—	—	—	—	—	—	462	69,762	1,439	71,200	1,469	72,669	1,499	74,168
Jan 07	69,300	1-Jan-07	—	—	—	—	—	—	—	—	1,413	70,713	1,458	72,172	1,489	73,660
Feb	69,300	1-Feb-07	—	—	—	—	—	—	—	—	921	70,221	1,448	71,669	1,478	73,148
Mar	69,300	1-Mar-07	—	—	—	—	—	—	—	—	476	69,776	1,439	71,216	1,469	72,684
Apr	69,300	1-Apr-07	—	—	—	—	—	—	—	—	—	—	1,414	70,714	1,458	72,172
May	69,300	1-May-07	—	—	—	—	—	—	—	—	—	—	942	70,242	1,449	71,691
Jun	69,300	1-Jun-07	—	—	—	—	—	—	—	—	—	—	455	69,755	1,439	71,194
Jul	69,300	1-Jul-07	—	—	—	—	—	—	—	—	—	—	—	—	1,414	70,714
Aug	69,300	1-Aug-07	—	—	—	—	—	—	—	—	—	—	—	—	932	70,232
Sep	69,300	1-Sep-07	—	—	—	—	—	—	—	—	—	—	—	—	451	69,751
Oct	69,300	1-Oct-07	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-07	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-07	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jan 08	69,300	1-Jan-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Feb	69,300	1-Feb-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Mar	69,300	1-Mar-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Apr	69,300	1-Apr-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
May	69,300	1-May-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jun	69,300	1-Jun-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jul	69,300	1-Jul-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Aug	69,300	1-Aug-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Sep	69,300	1-Sep-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Oct	69,300	1-Oct-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-08	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jan 09	69,300	1-Jan-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Feb	69,300	1-Feb-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Mar	69,300	1-Mar-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Apr	69,300	1-Apr-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
May	69,300	1-May-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jun	69,300	1-Jun-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jul	69,300	1-Jul-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Aug	69,300	1-Aug-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Sep	69,300	1-Sep-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Oct	69,300	1-Oct-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0678		0.0730		0.0774		0.0817		0.0825		0.0825		0.0825
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		31-Mar-06		30-Jun-06		30-Sep-06		31-Dec-06		31-Mar-07		30-Jun-07		30-Sep-07
	$2.31 kW/mo.	Assume	90 Days In Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter		90 Days In Quarter		91 Days in Quarter		92 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative
			0.0170	Balance	0.0183	Balance	0.0194	Balance	0.0204	Balance	0.0206	Balance	0.0206	Balance	0.0206	Balance
			Q1 2006	Q1 2006	Q2 2006	Q2 2006	Q3 2006	Q3 2006	Q4 2006	Q4 2006	Q1 2007	Q1 2007	Q2 2007	Q2 2007	Q3 2007	Q3 2007
Jan 10	69,300	1-Jan-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Feb	69,300	1-Feb-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Mar	69,300	1-Mar-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Apr	69,300	1-Apr-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
May	69,300	1-May-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jun	69,300	1-Jun-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jul	69,300	1-Jul-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Aug	69,300	1-Aug-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Sep	69,300	1-Sep-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Oct	69,300	1-Oct-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
			—	—	—	—	—	—	—	—	—	—	—	—	—	—
January 1, 2011	4,088,700		1,149	139,749	5,038	352,687	9,448	570,035	14,428	792,363	19,153	1,019,416	23,837	1,251,153	28,602	1,487,654

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0825		0.0776		0.0677		0.0530		0.0500		0.0452		0.0337
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		31-Dec-07		31-Mar-08		30-Jun-08		30-Sep-08		31-Dec-08		31-Mar-09		30-Jun-09
	$2.31 kW/mo.	Assume	92 Days in Quarter		91 Days In Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter		90 Days in Quarter		91 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative
			0.0206	Balance	0.0194	Balance	0.0169	Balance	0.0133	Balance	0.0125	Balance	0.0113	Balance	0.0084	Balance
			Q4 2007	Q4 2007	Q1 2008	Q1 2008	Q2 2008	Q2 2008	Q3 2008	Q3 2008	Q4 2008	Q4 2008	Q1 2009	Q1 2009	Q2 2009	Q2 2009
Feb 06	69,300	1-Feb-06	1,627	80,515	1,562	82,077	1,389	83,466	1,106	84,572	1,057	85,629	968	86,596	730	87,326
Mar	69,300	1-Mar-06	1,619	80,095	1,554	81,649	1,382	83,030	1,100	84,131	1,052	85,182	963	86,145	726	86,871
Apr	69,300	1-Apr-06	1,609	79,629	1,545	81,174	1,374	82,548	1,094	83,641	1,046	84,687	957	85,644	722	86,365
May	69,300	1-May-06	1,600	79,158	1,536	80,694	1,366	82,060	1,087	83,147	1,039	84,186	951	85,138	717	85,855
Jun	69,300	1-Jun-06	1,590	78,672	1,526	80,198	1,357	81,556	1,081	82,636	1,033	83,669	945	84,615	713	85,328
Jul	69,300	1-Jul-06	1,580	78,201	1,517	79,718	1,349	81,067	1,074	82,142	1,027	83,168	940	84,108	709	84,817
Aug	69,300	1-Aug-06	1,570	77,701	1,507	79,208	1,341	80,549	1,067	81,616	1,020	82,636	934	83,570	704	84,274
Sep	69,300	1-Sep-06	1,560	77,200	1,498	78,698	1,332	80,030	1,060	81,091	1,014	82,104	928	83,032	700	83,731
Oct	69,300	1-Oct-06	1,550	76,716	1,488	78,204	1,324	79,528	1,054	80,581	1,007	81,589	922	82,511	695	83,206
Nov	69,300	1-Nov-06	1,540	76,198	1,478	77,676	1,315	78,991	1,047	80,038	1,000	81,038	916	81,954	690	82,644
Dec	69,300	1-Dec-06	1,530	75,697	1,469	77,166	1,306	78,472	1,040	79,512	994	80,506	910	81,415	686	82,101
Jan 07	69,300	1-Jan-07	1,519	75,180	1,458	76,638	1,297	77,935	1,033	78,968	987	79,955	903	80,859	681	81,540
Feb	69,300	1-Feb-07	1,509	74,656	1,448	76,105	1,288	77,393	1,025	78,418	980	79,398	897	80,296	676	80,972
Mar	69,300	1-Mar-07	1,499	74,184	1,439	75,623	1,280	76,903	1,019	77,922	974	78,896	892	79,787	672	80,459
Apr	69,300	1-Apr-07	1,489	73,661	1,429	75,090	1,271	76,361	1,012	77,372	967	78,339	885	79,225	667	79,892
May	69,300	1-May-07	1,479	73,170	1,419	74,589	1,262	75,852	1,005	76,857	961	77,817	879	78,697	663	79,360
Jun	69,300	1-Jun-07	1,468	72,663	1,410	74,072	1,254	75,326	998	76,324	954	77,278	873	78,151	658	78,810
Jul	69,300	1-Jul-07	1,458	72,172	1,400	73,572	1,245	74,818	991	75,809	948	76,757	867	77,624	654	78,278
Aug	69,300	1-Aug-07	1,449	71,681	1,391	73,071	1,237	74,308	985	75,293	941	76,234	861	77,095	650	77,745
Sep	69,300	1-Sep-07	1,439	71,189	1,381	72,570	1,228	73,798	978	74,776	935	75,711	856	76,567	645	77,212
Oct	69,300	1-Oct-07	1,414	70,714	1,372	72,086	1,220	73,306	971	74,277	928	75,205	850	76,055	641	76,696
Nov	69,300	1-Nov-07	932	70,232	1,363	71,595	1,212	72,806	965	73,771	922	74,693	844	75,537	636	76,174
Dec	69,300	1-Dec-07	466	69,766	1,353	71,120	1,204	72,323	958	73,282	916	74,198	838	75,036	632	75,668
Jan 08	69,300	1-Jan-08	—	—	1,330	70,630	1,195	71,825	952	72,777	910	73,686	833	74,519	628	75,147
Feb	69,300	1-Feb-08	—	—	872	70,172	1,188	71,359	946	72,305	904	73,209	827	74,036	624	74,660
Mar	69,300	1-Mar-08	—	—	443	69,743	1,180	70,924	940	71,863	898	72,762	822	73,584	620	74,204
Apr	69,300	1-Apr-08	—	—	—	—	1,160	70,460	934	71,394	892	72,286	817	73,103	616	73,719
May	69,300	1-May-08	—	—	—	—	773	70,073	928	71,002	888	71,889	812	72,702	613	73,314
Jun	69,300	1-Jun-08	—	—	—	—	374	69,674	923	70,597	882	71,479	808	72,287	609	72,896
Jul	69,300	1-Jul-08	—	—	—	—	—	—	908	70,208	878	71,086	803	71,889	606	72,495
Aug	69,300	1-Aug-08	—	—	—	—	—	—	599	69,899	874	70,773	800	71,572	603	72,175
Sep	69,300	1-Sep-08	—	—	—	—	—	—	289	69,589	870	70,459	796	71,255	600	71,856
Oct	69,300	1-Oct-08	—	—	—	—	—	—	—	—	857	70,157	793	70,950	598	71,547
Nov	69,300	1-Nov-08	—	—	—	—	—	—	—	—	565	69,865	789	70,654	595	71,250
Dec	69,300	1-Dec-08	—	—	—	—	—	—	—	—	282	69,582	786	70,369	593	70,962
Jan 09	69,300	1-Jan-09	—	—	—	—	—	—	—	—	—	—	774	70,074	590	70,665
Feb	69,300	1-Feb-09	—	—	—	—	—	—	—	—	—	—	505	69,805	588	70,393
Mar	69,300	1-Mar-09	—	—	—	—	—	—	—	—	—	—	261	69,561	586	70,147
Apr	69,300	1-Apr-09	—	—	—	—	—	—	—	—	—	—	—	—	577	69,877
May	69,300	1-May-09	—	—	—	—	—	—	—	—	—	—	—	—	385	69,685
Jun	69,300	1-Jun-09	—	—	—	—	—	—	—	—	—	—	—	—	186	69,486
Jul	69,300	1-Jul-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Aug	69,300	1-Aug-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Sep	69,300	1-Sep-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Oct	69,300	1-Oct-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-09	—	—	—	—	—	—	—	—	—	—	—	—	—	—

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0825		0.0776		0.0677		0.0530		0.0500		0.0452		0.0337
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		31-Dec-07		31-Mar-08		30-Jun-08		30-Sep-08		31-Dec-08		31-Mar-09		30-Jun-09
	$2.31 kW/mo.	Assume	92 Days in Quarter		91 Days In Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter		90 Days in Quarter		91 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative
			0.0206	Balance	0.0194	Balance	0.0169	Balance	0.0133	Balance	0.0125	Balance	0.0113	Balance	0.0084	Balance
			Q4 2007	Q4 2007	Q1 2008	Q1 2008	Q2 2008	Q2 2008	Q3 2008	Q3 2008	Q4 2008	Q4 2008	Q1 2009	Q1 2009	Q2 2009	Q2 2009
Jan 10	69,300	1-Jan-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Feb	69,300	1-Feb-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Mar	69,300	1-Mar-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Apr	69,300	1-Apr-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
May	69,300	1-May-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jun	69,300	1-Jun-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Jul	69,300	1-Jul-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Aug	69,300	1-Aug-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Sep	69,300	1-Sep-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Oct	69,300	1-Oct-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Nov	69,300	1-Nov-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Dec	69,300	1-Dec-10	—	—	—	—	—	—	—	—	—	—	—	—	—	—
			—	—	—
January 1, 2011	4,088,700		33,495	1,729,049	36,188	1,973,137	35,702	2,216,740	31,168	2,455,808	32,402	2,696,110	32,006	2,936,016	25,884	3,169,801

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0325		0.0325		0.0325		0.0325		0.0325		0.0325
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		30-Sep-09		31-Dec-09		31-Mar-10		30-Jun-10		30-Sep-10		31-Dec-10
	$2.31 kW/mo.	Assume	92 Days in Quarter		92 Days in Quarter		90 Days in Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Cumulative
			0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	Interest
			Q3 2009	Q3 2009	Q4 2009	Q4 2009	Q1 2010	Q1 2010	Q2 2010	Q2 2010	Q3 2010	Q3 2010	Q4 2010	Q4 2010	31-Dec-10
Feb 06	69,300	1-Feb-06	710	88,036	715	88,751	721	89,472	727	90,199	733	90,932	739	91,671	22,371
Mar	69,300	1-Mar-06	706	87,576	712	88,288	717	89,005	723	89,728	729	90,457	735	91,192	21,892
Apr	69,300	1-Apr-06	702	87,067	707	87,775	713	88,488	719	89,207	725	89,932	731	90,662	21,362
May	69,300	1-May-06	698	86,553	703	87,256	709	87,965	715	88,680	721	89,400	726	90,126	20,826
Jun	69,300	1-Jun-06	693	86,021	699	86,720	705	87,424	710	88,135	716	88,851	722	89,573	20,273
Jul	69,300	1-Jul-06	689	85,506	695	86,201	700	86,901	706	87,607	712	88,319	718	89,036	19,736
Aug	69,300	1-Aug-06	685	84,959	690	85,649	696	86,345	702	87,047	707	87,754	713	88,467	19,167
Sep	69,300	1-Sep-06	680	84,412	686	85,098	691	85,789	697	86,486	703	87,189	708	87,897	18,597
Oct	69,300	1-Oct-06	676	83,882	682	84,563	687	85,250	693	85,943	698	86,641	704	87,345	18,045
Nov	69,300	1-Nov-06	671	83,316	677	83,993	682	84,675	688	85,363	694	86,057	699	86,756	17,456
Dec	69,300	1-Dec-06	667	82,768	672	83,441	678	84,119	683	84,802	689	85,491	695	86,186	16,886
Jan 07	69,300	1-Jan-07	663	82,202	668	82,870	673	83,543	679	84,222	684	84,907	690	85,596	16,296
Feb	69,300	1-Feb-07	658	81,630	663	82,293	669	82,962	674	83,636	680	84,315	685	85,000	15,700
Mar	69,300	1-Mar-07	654	81,113	659	81,772	664	82,436	670	83,106	675	83,781	681	84,462	15,162
Apr	69,300	1-Apr-07	649	80,541	654	81,196	660	81,855	665	82,520	670	83,191	676	83,867	14,567
May	69,300	1-May-07	645	80,005	650	80,655	655	81,310	661	81,971	666	82,637	671	83,308	14,008
Jun	69,300	1-Jun-07	640	79,450	646	80,096	651	80,746	656	81,402	661	82,064	667	82,731	13,431
Jul	69,300	1-Jul-07	636	78,914	641	79,555	646	80,201	652	80,853	657	81,510	662	82,172	12,872
Aug	69,300	1-Aug-07	632	78,376	637	79,013	642	79,655	647	80,302	652	80,955	658	81,613	12,313
Sep	69,300	1-Sep-07	627	77,839	632	78,471	638	79,109	643	79,752	648	80,400	653	81,053	11,753
Oct	69,300	1-Oct-07	623	77,319	628	77,947	633	78,581	638	79,219	644	79,863	649	80,512	11,212
Nov	69,300	1-Nov-07	619	76,793	624	77,417	629	78,046	634	78,680	639	79,319	644	79,963	10,663
Dec	69,300	1-Dec-07	615	76,283	620	76,903	625	77,528	630	78,158	635	78,793	640	79,433	10,133
Jan 08	69,300	1-Jan-08	611	75,757	616	76,373	621	76,994	626	77,619	631	78,250	636	78,886	9,586
Feb	69,300	1-Feb-08	607	75,266	612	75,878	617	76,494	622	77,116	627	77,742	632	78,374	9,074
Mar	69,300	1-Mar-08	603	74,807	608	75,415	613	76,027	618	76,645	623	77,268	628	77,896	8,596
Apr	69,300	1-Apr-08	599	74,318	604	74,922	609	75,530	614	76,144	619	76,763	624	77,386	8,086
May	69,300	1-May-08	596	73,910	601	74,510	605	75,116	610	75,726	615	76,341	620	76,962	7,662
Jun	69,300	1-Jun-08	592	73,488	597	74,086	602	74,687	607	75,294	612	75,906	617	76,523	7,223
Jul	69,300	1-Jul-08	589	73,084	594	73,678	599	74,276	603	74,880	608	75,488	613	76,101	6,801
Aug	69,300	1-Aug-08	586	72,762	591	73,353	596	73,949	601	74,550	606	75,155	611	75,766	6,466
Sep	69,300	1-Sep-08	584	72,440	589	73,028	593	73,622	598	74,220	603	74,823	608	75,431	6,131
Oct	69,300	1-Oct-08	581	72,129	586	72,715	591	73,306	596	73,901	600	74,502	605	75,107	5,807
Nov	69,300	1-Nov-08	579	71,829	584	72,412	588	73,001	593	73,594	598	74,192	603	74,794	5,494
Dec	69,300	1-Dec-08	577	71,538	581	72,119	586	72,705	591	73,296	596	73,892	600	74,492	5,192
Jan 09	69,300	1-Jan-09	574	71,239	579	71,818	584	72,401	588	72,990	593	73,583	598	74,180	4,880
Feb	69,300	1-Feb-09	572	70,965	577	71,541	581	72,123	586	72,709	591	73,299	596	73,895	4,595
Mar	69,300	1-Mar-09	570	70,717	575	71,292	579	71,871	584	72,455	589	73,043	593	73,637	4,337
Apr	69,300	1-Apr-09	568	70,445	572	71,018	577	71,595	582	72,176	586	72,763	591	73,354	4,054
May	69,300	1-May-09	566	70,251	571	70,822	575	71,397	580	71,977	585	72,562	590	73,152	3,852
Jun	69,300	1-Jun-09	565	70,051	569	70,620	574	71,194	578	71,772	583	72,355	588	72,943	3,643
Jul	69,300	1-Jul-09	557	69,857	568	70,425	572	70,997	577	71,574	582	72,155	586	72,741	3,441
Aug	69,300	1-Aug-09	367	69,667	566	70,233	571	70,804	575	71,379	580	71,959	585	72,544	3,244
Sep	69,300	1-Sep-09	177	69,477	565	70,042	569	70,611	574	71,185	578	71,763	583	72,346	3,046
Oct	69,300	1-Oct-09	—	—	557	69,857	568	70,425	572	70,997	577	71,574	582	72,155	2,855
Nov	69,300	1-Nov-09	—	—	367	69,667	566	70,233	571	70,804	575	71,379	580	71,959	2,659
Dec	69,300	1-Dec-09	—	—	184	69,484	565	70,048	569	70,617	574	71,191	578	71,769	2,469

EL PASO ELECTRIC COMPANY
TUCSON ELECTRIC POWER COMPANY
Settlement Calculation, Article I
			Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate		Annual Interest Rate
			0.0325		0.0325		0.0325		0.0325		0.0325		0.0325
	30 MW @		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended		Quarter Ended
	Firm PTP		30-Sep-09		31-Dec-09		31-Mar-10		30-Jun-10		30-Sep-10		31-Dec-10
	$2.31 kW/mo.	Assume	92 Days in Quarter		92 Days in Quarter		90 Days in Quarter		91 Days in Quarter		92 Days in Quarter		92 Days in Quarter
	Monthly Delivery	Earn Interest
	Charge	All Month	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Interest	Cumulative	Cumulative
			0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	0.0081	Balance	Interest
			Q3 2009	Q3 2009	Q4 2009	Q4 2009	Q1 2010	Q1 2010	Q2 2010	Q2 2010	Q3 2010	Q3 2010	Q4 2010	Q4 2010	31-Dec-10
Jan 10	69,300	1-Jan-10	—	—	—	—	557	69,857	568	70,424	572	70,997	577	71,573	2,273
Feb	69,300	1-Feb-10	—	—	—	—	363	69,663	566	70,229	571	70,799	575	71,375	2,075
Mar	69,300	1-Mar-10	—	—	—	—	188	69,488	565	70,052	569	70,621	574	71,195	1,895
Apr	69,300	1-Apr-10	—	—	—	—	—	—	557	69,857	568	70,424	572	70,997	1,697
May	69,300	1-May-10	—	—	—	—	—	—	371	69,671	566	70,237	571	70,808	1,508
Jun	69,300	1-Jun-10	—	—	—	—	—	—	179	69,479	565	70,044	569	70,613	1,313
Jul	69,300	1-Jul-10	—	—	—	—	—	—	—	—	557	69,857	568	70,425	1,125
Aug	69,300	1-Aug-10	—	—	—	—	—	—	—	—	367	69,667	566	70,233	933
Sep	69,300	1-Sep-10	—	—	—	—	—	—	—	—	177	69,477	565	70,042	742
Oct	69,300	1-Oct-10	—	—	—	—	—	—	—	—	—	—	557	69,857	557
Nov	69,300	1-Nov-10	—	—	—	—	—	—	—	—	—	—	367	69,667	367
Dec	69,300	1-Dec-10	—	—	—	—	—	—	—	—	—	—	184	69,484	184
January 1, 2011	4,088,700		26,856	3,404,557	28,770	3,641,227	30,692	3,879,819	32,631	4,120,350	34,579	4,362,830	36,556	4,607,285	518,585

*TEP to submit on EPE OASIS a Transmission Service Request (TSR) for this

Agreement. TSR may be marked “Not Pre-Confirmed” pending FERC action

on the Settlement.

Page 1 of 4

ATTACHMENT A

Form Of Service Agreement For

Firm Point-To-Point Transmission Service

1.0 This Service Agreement, dated as of , is entered into, by and between El Paso Electric Company or “EPE” (the Transmission Provider), and Tucson Electric Power Companyor “TEP” ("Transmission Customer"). Note: Transmission capacity purchased on the EPE OASIS. TSR #______________________.*

2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff.

3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff.

4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on such date as mutually agreed upon by the parties.

5.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement.

Page 2 of 4

6.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.

Transmission Provider:

El Paso Electric Company

Attention: AVP - System Operations M/S 751

Post Office Box 982

El Paso, TX 79960

Transmission Customer:

Tucson Electric Power Company

Attention:

7.0 The Tariff is incorporated herein and made a part hereof.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.

Transmission Provider:

By: AVP-System Operations

NameTitleDate

Transmission Customer:

By:

NameTitleDate

Page 3 of 4

Specifications For Long-Term Firm Point-To-Point

Transmission Service

l.0 Term of Transaction: TBD(To correspond to the term of Settlement Agreement)_____________________________________________

Start Date: TBD(Immediately Upon Settlement's Effective Date)

Termination Date: To correspond to the termination of the EPE/TEP 1982 Exchange Agreement -- April 19, 2030.

2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates.

30 MW. Transaction originates in the EPE Control Area

3.0 Point(s) of Receipt: Luna 345 kV Substation

Delivering Party: El Paso Electric Company

4.0 Point(s) of Delivery: Greenlee 345 kV Substation

Receiving Party: Tucson Electric Power Company

5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 30 MW

6.0 Designation of party(ies) subject to reciprocal service obligation:

Tucson Electric Power Company

7.0 Name(s) of any Intervening Systems providing transmission service:

None. Transaction utilizes EPE transmission.

Page 4 of 4

8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.)

8.1 Transmission Charge: EPE's Applicable Long-Term Firm Point-to-Point Transmission Service Tariff Rate in its OATT set forth in Schedule 7, Section A. Currently, the yearly delivery charge is $27.72 per KW of Reserved Capacity per year, which will be invoiced on a monthly basis at one-twelfth of that demand charge.

8.2 System Impact and/or Facilities Study Charge(s):

None

8.3Direct Assignment Facilities Charge: None

8.4 Ancillary Services Charges: As applicable under EPE's OATT. Currently, EPE's effective Schedule 1 rate is $0.843 per KW-Year and Schedule 2 rate is $0.528 per KW-Year.

*TEP to submit on EPE OASIS a Transmission Service Request (TSR) for this

Agreement. TSR may be marked “Not Pre-Confirmed” pending FERC action

on the Settlement.

Page 1 of 4

ATTACHMENT A

Form Of Service Agreement For

Firm Point-To-Point Transmission Service

1.0 This Service Agreement, dated as of , is entered into, by and between El Paso Electric Company or “EPE” (the Transmission Provider), and Tucson Electric Power Companyor “TEP” ("Transmission Customer"). Note: Transmission capacity purchased on the EPE OASIS. TSR #______________________.*

2.0 The Transmission Customer has been determined by the Transmission Provider to have a Completed Application for Firm Point-To-Point Transmission Service under the Tariff.

3.0 The Transmission Customer has provided to the Transmission Provider an Application deposit in accordance with the provisions of Section 17.3 of the Tariff.

4.0 Service under this agreement shall commence on the later of (l) the requested service commencement date, or (2) the date on which construction of any Direct Assignment Facilities and/or Network Upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this agreement shall terminate on such date as mutually agreed upon by the parties.

5.0 The Transmission Provider agrees to provide and the Transmission Customer agrees to take and pay for Firm Point-To-Point Transmission Service in accordance with the provisions of Part II of the Tariff and this Service Agreement.

Page 2 of 4

6.0 Any notice or request made to or by either Party regarding this Service Agreement shall be made to the representative of the other Party as indicated below.

Transmission Provider:

El Paso Electric Company

Attention: AVP - System Operations M/S 751

Post Office Box 982

El Paso, TX 79960

Transmission Customer:

Tucson Electric Power Company

Attention:

7.0 The Tariff is incorporated herein and made a part hereof.

IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.

Transmission Provider:

By: AVP-System Operations

NameTitleDate

Transmission Customer:

By:

NameTitleDate

Page 3 of 4

Specifications For Long-Term Firm Point-To-Point

Transmission Service

l.0 Term of Transaction: TBD(To correspond to the term of Settlement Agreement)

Start Date: TBD(The later of the Settlement's Effective Date and the date on which TEP, or any party delivering power to TEP's Balancing Authority Area for TEP's use in serving its load, begins receiving electricity from the first phase of the Macho Springs Project)

Termination Date: To correspond to the termination of the EPE/TEP 1982 Exchange Agreement -- April 19, 2030.

2.0 Description of capacity and energy to be transmitted by Transmission Provider including the electric Control Area in which the transaction originates.

10 MW. Transaction originates in the EPE Control Area

3.0 Point(s) of Receipt: Luna 345 kV Substation

Delivering Party: El Paso Electric Company

4.0 Point(s) of Delivery: Springerville 345 kV Substation

Receiving Party: Tucson Electric Power Company

5.0 Maximum amount of capacity and energy to be transmitted (Reserved Capacity): 10 MW

6.0 Designation of party(ies) subject to reciprocal service obligation:

Tucson Electric Power Company

7.0 Name(s) of any Intervening Systems providing transmission service:

None. Transaction utilizes EPE transmission.

Page 4 of 4

8.0 Service under this Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of the Tariff.)

8.1 Transmission Charge: EPE's Applicable Long-Term Firm Point-to-Point Transmission Service Tariff Rate in its OATT set forth in Schedule 7, Section A. Currently, the yearly delivery charge is $27.72 per KW of Reserved Capacity per year, which will be invoiced on a monthly basis at one-twelfth of that demand charge.

8.2 System Impact and/or Facilities Study Charge(s):

None

8.3Direct Assignment Facilities Charge: None

8.4 Ancillary Services Charges: As applicable under EPE's OATT. Currently, EPE's effective Schedule 1 rate is $0.843 per KW-Year and Schedule 2 rate is $0.528 per KW-Year.

EX-10.25-01

Exhibit 10.25-01

[Execution Version]

$200,000,000

AMENDED AND RESTATED CREDIT AGREEMENT

dated as of

November 15, 2011,

among

EL PASO ELECTRIC 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 theRio Grande Resources Trust II,

THE LENDERS PARTY HERETO,

JPMORGAN CHASE BANK, N.A.,

as Administrative Agentand Issuing Bank,

and

UNION BANK, N.A.,

as Syndication Agent

________________________

UNION BANK, N.A. and J.P. MORGAN SECURITIES LLC,

as Joint Lead Arrangers and Joint Bookrunners

61548965_6

TABLE OF CONTENTS
		Page
ARTICLE I	Definitions	1
SECTION 1.01.	Defined Terms	1
SECTION 1.02.	Terms Generally	20
ARTICLE II	The Credits	20
SECTION 2.01.	Commitments	20
SECTION 2.02.	Loans	20
SECTION 2.03.	Borrowing Procedure	22
SECTION 2.04.	Evidence of Debt; Repayment of Loans	22
SECTION 2.05.	Fees	23
SECTION 2.06.	Interest on Loans	24
SECTION 2.07.	Default Interest	24
SECTION 2.08.	Alternate Rate of Interest	25
SECTION 2.09.	Termination and Reduction of Commitments	25
SECTION 2.10.	Conversion and Continuation of Borrowings	25
SECTION 2.11.	Optional Prepayment	27
SECTION 2.12.	Reserve Requirements; Change in Circumstances	27
SECTION 2.13.	Change in Legality	29
SECTION 2.14.	Indemnity	30
SECTION 2.15.	Pro Rata Treatment	30
SECTION 2.16.	Sharing of Setoffs	30
SECTION 2.17.	Payments	31
SECTION 2.18.	Taxes	31
SECTION 2.19.	Replacement or Termination of Lenders Under Certain Circumstances; Duty to Mitigate	35
SECTION 2.20.	Letters of Credit	36
SECTION 2.21.	Increase of Commitments	40
ARTICLE III	Representations and Warranties	42
SECTION 3.01.	Organization; Powers	42
SECTION 3.02.	Authorization	42
SECTION 3.03.	Enforceability	42
SECTION 3.04.	Governmental Approvals	43
SECTION 3.05.	Financial Statements	43
SECTION 3.06.	No Material Adverse Change	43
SECTION 3.07.	Subsidiaries	43
SECTION 3.08.	Litigation; Compliance with Laws	43
SECTION 3.09.	Federal Reserve Regulations	43
SECTION 3.10.	Investment Company Act	44

SECTION 3.11.	Use of Proceeds	44
SECTION 3.12.	Tax Returns	44
SECTION 3.13.	No Material Misstatements	44
SECTION 3.14.	Employee Benefit Plans	44
SECTION 3.15.	Environmental Matters	44
SECTION 3.16.	Insurance	45
SECTION 3.17.	Anti-Terrorism Laws, etc	45
ARTICLE IV	Conditions of Lending	46
SECTION 4.01.	All Credit Events	46
SECTION 4.02.	Effective Date	46
ARTICLE V	Affirmative Covenants	48
SECTION 5.01.	Existence; Businesses and Properties	48
SECTION 5.02.	Insurance	49
SECTION 5.03.	Obligations and Taxes	49
SECTION 5.04.	Financial Statements, Reports, etc	49
SECTION 5.05.	Litigation and Other Notices	50
SECTION 5.06.	Employee Benefits	50
SECTION 5.07.	Maintaining Records; Access to Properties and Inspections	51
SECTION 5.08.	Use of Proceeds	51
SECTION 5.09.	Subsidiary Guarantors	51
SECTION 5.10.	Maintenance of Ratings	51
ARTICLE VI	Negative Covenants	52
SECTION 6.01.	Subsidiary Indebtedness	52
SECTION 6.02.	Liens	52
SECTION 6.03.	Sale and Lease-Back Transactions	54
SECTION 6.04.	Investments, Loans and Advances	54
SECTION 6.05.	Mergers, Consolidations and Sales of Assets and Acquisitions	55
SECTION 6.06.	Transactions with Affiliates	55
SECTION 6.07.	Businesses of Borrowers and Material Subsidiaries	56
SECTION 6.08.	Other Agreements	56
SECTION 6.09.	Debt to Capitalization Ratio	56
SECTION 6.10.	Fiscal Year	56

ii

ARTICLE VII	Events of Default	56
ARTICLE VIII	The Administrative Agent	58
ARTICLE IX	Guarantee	60
SECTION 9.01.	Guarantee	61
SECTION 9.02.	Obligations Not Waived	61
SECTION 9.03.	Guarantee of Payment	61
SECTION 9.04.	No Discharge or Diminishment of Guarantee	61
SECTION 9.05.	Defenses of the Trustee Waived	62
SECTION 9.06.	Agreement to Pay; Subrogation	62
SECTION 9.07.	Information	63
SECTION 9.08.	Termination	63
ARTICLE X	Miscellaneous	63
SECTION 10.01.	Notices.	63
SECTION 10.02.	Survival of Agreement	64
SECTION 10.03.	Binding Effect	65
SECTION 10.04.	Successors and Assigns	65
SECTION 10.05.	Expenses; Indemnity	68
SECTION 10.06.	Right of Setoff	69
SECTION 10.07.	Applicable Law	69
SECTION 10.08.	Waivers; Amendment	70
SECTION 10.09.	Interest Rate Limitation	70
SECTION 10.10.	Entire Agreement	71
SECTION 10.11.	Waiver of Jury Trial	71
SECTION 10.12.	Severability	71
SECTION 10.13.	Counterparts	72
SECTION 10.14.	Headings	72
SECTION 10.15.	Jurisdiction; Consent to Service of Process	72
SECTION 10.16.	Confidentiality	72
SECTION 10.17.	Texas Revolving Credit Statute	73
SECTION 10.18.	No Recourse; Multiple Capacities	73
SECTION 10.19.	Limited Representations, Warranties and Covenants of Trustee	73
SECTION 10.20.	USA Patriot Act Notice	74
SECTION 10.21.	Amendment and Restatement	74
SCHEDULES
Schedule 2.01	Commitments
Schedule 3.04	Governmental Approvals

iii

Schedule 3.07	Subsidiaries
Schedule 3.08	Litigation and Compliance with Laws
Schedule 3.15	Environmental Matters
Schedule 4.02(a)	Local Regulatory Counsel
Schedule 6.02	Liens
Schedule 6.04	Certain Investments
EXHIBITS
Exhibit A	Form of Administrative Questionnaire
Exhibit B	Form of Assignment and Acceptance
Exhibit C	Form of Borrowing Request
Exhibit D	Form of Subsidiary Guarantee Agreement

iv

AMENDED AND RESTATED CREDIT AGREEMENT, dated as of November 15, 2011 (as amended from time to time, this “Agreement”), among EL PASO ELECTRIC COMPANY, a Texas corporation (“El Paso”), THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., a national banking association with trust powers, not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II (said trustee being the successor to JPMorgan Chase Bank, N.A., formerly known as JPMorgan Chase Bank, successor by merger to The Chase Manhattan Bank, successor by merger to Chase Bank of Texas, National Association, successor by change of name to Texas Commerce Bank National Association, as trustee of the Rio Grande Resources Trust II) (the “Trustee”; each of El Paso and the Trustee is referred to individually herein as a “Borrower” and collectively as the “Borrowers”), the Lenders (as defined in Article I), JPMORGAN CHASE BANK, N.A., as issuing bank (in such capacity, including any successor thereto, the “Issuing Bank”) and as administrative agent (in such capacity, including any successor thereto, the “Administrative Agent”) for the Lenders, and UNION BANK, N.A., as syndication agent (in such capacity, including any successor thereto, the “Syndication Agent”).

The Borrowers, the Lenders, the Issuing Bank, the Administrative Agent and the Syndication Agent previously entered into that certain Credit Agreement, dated as of September 23, 2010 (as amended, supplemented or otherwise modified from time to time prior to the date hereof, the “Existing Credit Agreement”). The parties hereto desire to amend and restate the Existing Credit Agreement, on the terms and conditions set forth herein.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, the parties hereto hereby agree that the Existing Credit Agreement is hereby amended and restated in its entirety, without novation, as follows:

ARTICLE IDefinitions

SECTION 1.01.Defined Terms. As used in this Agreement, the following terms shall have the meanings specified below:

“ABR Borrowing” shall mean a Borrowing comprised of ABR Loans.

“ABR Loan” shall mean any Loan bearing interest at a rate determined by reference to the Alternate Base Rate in accordance with the provisions of Article II.

“Adjusted LIBO Rate” shall mean, with respect to any Eurodollar Loan for any Interest Period, an interest rate per annum equal to (a) the LIBO Rate for such Interest Period multiplied by (b) the Statutory Reserve Rate.

“Administrative Agent” shall have the meaning assigned to such term in the preamble to this Agreement.

“Administrative Agent Fees” shall have the meaning assigned to such term in Section 2.05(b).

“Administrative Questionnaire” shall mean an Administrative Questionnaire in the form of Exhibit A, or such other form as shall be approved by the Administrative Agent.

“Affiliate” shall mean, when used with respect to a specified person, another person that directly, or indirectly through one or more intermediaries, Controls or is Controlled by or is under common Control with the person specified.

“Agent” shall mean each of the Administrative Agent and the Syndication Agent.

“Aggregate Credit Exposure” shall mean the aggregate amount of the Lenders’ Credit Exposures.

“Alternate Base Rate” shall mean, for any day, a rate per annum (rounded upwards, if necessary, to the next 1/16 of 1%) equal to the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1% and (c) the Adjusted LIBO Rate for an Interest Period of one month beginning on such day (or, if such day is not a Business Day, the immediately preceding Business Day) plus 1% (provided that, for the avoidance of doubt, such Adjusted LIBO Rate for any day shall be based on the rate appearing on the Reuters Screen LIBOR01 (or on any successor or substitute screen or page of such service) at approximately 11:00 a.m. London time two Business Days prior to such day). If for any reason the Administrative Agent shall have determined (which determination shall be conclusive absent manifest error) that it is unable to ascertain the Federal Funds Effective Rate for any reason, including the inability or failure of the Administrative Agent to obtain sufficient quotations in accordance with the terms of the definition thereof, the Alternate Base Rate shall be determined without regard to clause (b) of the preceding sentence until the circumstances giving rise to such inability no longer exist. Any change in the Alternate Base Rate due to a change in the Prime Rate, the Federal Funds Effective Rate or the Adjusted LIBO Rate shall be effective on the effective date of such change in the Prime Rate, the Federal Funds Effective Rate or the Adjusted LIBO Rate, respectively.

“Anti‑Terrorism Order”shallmean Executive Order 13224 of September 23, 2001, Blocking Property and Prohibiting Transactions With Persons Who Commit, Threaten to Commit, or Support Terrorism (66 Fed. Reg. 49079 (2001)), as amended from time to time.

“Applicable Percentage” of any Lender at any time shall mean the percentage of the Total Commitment represented by such Lender’s Commitment. In the event the Commitments shall have expired or been terminated, the Applicable Percentages shall be determined on the basis of the Commitments most recently in effect.

“Applicable Ratings” shall mean at any time the credit ratings at such time by the Rating Agencies of the Index Debt.

“Applicable Spread” shall mean, for any day, with respect to any Eurodollar Loan or ABR Loan, or with respect to the Commitment Fee, as the case may be, (a) from and after the Original Closing Date through (but not including) the Effective Date, the applicable percentage set forth in Table A below under the caption “LIBOR Spread”, “ABR Spread” or “Commitment Fee”, as the case may be, based upon the higher of the Applicable Ratings, and (b) from and after

2

the Effective Date, the applicable percentage set forth in Table B below under the caption “LIBOR Spread”, “ABR Spread” or “Commitment Fee”, as the case may be, based upon the higher of the Applicable Ratings:

TABLE A
	Applicable Ratings (S&P/Moody’s)	LIBOR Spread	ABR Spread	Commitment Fee
Category 1	A-/A3 or better	1.650%	0.650%	0.200%
Category 2	BBB+/Baa1	1.900%	0.900%	0.250%
Category 3	BBB/Baa2	2.150%	1.150%	0.375%
Category 4	BBB-/Baa3	2.400%	1.400%	0.500%
Category 5	Less than BBB-/Baa3 (or unrated)	2.650%	1.650%	0.625%
TABLE B
	Applicable Ratings (S&P/Moody’s)	LIBOR Spread	ABR Spread	Commitment Fee
Category 1	A-/A3 or better	1.000%	0.100%	0.125%
Category 2	BBB+/Baa1	1.125%	0.125%	0.175%
Category 3	BBB/Baa2	1.250%	0.250%	0.200%
Category 4	BBB-/Baa3	1.500%	0.500%	0.250%
Category 5	Less than BBB-/Baa3 (or unrated)	1.750%	0.750%	0.300%

Notwithstanding the foregoing, (a) if (i) both Rating Agencies cease to provide a current Applicable Rating or (ii) the Applicable Rating of either Rating Agency shall be below BBB- or Baa3, as the case may be, the Applicable Spread shall correspond to the percentages listed in Category 5; (b) if the Applicable Ratings of the Rating Agencies fall within different Categories, and the higher numbered Category is more than one numbered Category higher than the lower numbered Category, then the Applicable Spread shall correspond to the percentages listed in the next higher numbered Category from that of the lower numbered Category; and (c) at any time after the occurrence and during the continuation of an Event of Default, the Applicable Spread

3

shall correspond to the percentages listed in Category 5. The Applicable Spread shall be increased or decreased in accordance with the foregoing table upon any change in the Applicable Ratings. The Applicable Ratings in effect at any date are those in effect at the close of business on such date.

“Assignment and Acceptance” shall mean an assignment and acceptance entered into by a Lender and an assignee, and accepted by the Administrative Agent, in the form of Exhibit B or such other form as shall be approved by the Administrative Agent.

“Atomic Energy Act” shall mean the Atomic Energy Act of 1954, 42 U.S.C. §§ 2011 etseq. and the rules and regulations promulgated thereunder, as amended from time to time.

“Augmenting Lender” shall have the meaning assigned to such term in Section 2.21

“Board” shall mean the Board of Governors of the Federal Reserve System of the United States of America.

“BONY” shall mean The Bank of New York Mellon Trust Company, N.A., together with its successors and assigns.

“Borrower” and “Borrowers” shall have the meanings assigned to such terms in the preamble to this Agreement.

“Borrowing” shall mean a group of Loans of a single Type made by the Lenders to the same Borrower on a single date and as to which a single Interest Period is in effect.

“Borrowing Request” shall mean a request by a Borrower in accordance with the terms of Section 2.03 and substantially in the form of Exhibit C.

“Business Day” shall mean any day other than a Saturday, Sunday or day on which banks in New York City are authorized or required by law to close; provided, however, that when used in connection with a Eurodollar Loan, the term “Business Day” shall also exclude any day on which banks are not open for dealings in dollar deposits in the London interbank market.

“Capital Lease Obligations” of any person shall mean the obligations of such person to pay rent or other amounts under any lease of (or other arrangement conveying the right to use) real or personal property, or a combination thereof, which obligations are required to be classified and accounted for as capital leases on a balance sheet of such person under GAAP, and the amount of such obligations shall be the capitalized amount thereof determined in accordance with GAAP.

A “Change in Control” shall be deemed to have occurred if (a) any “person” or “group” (within the meaning of Rule 13d-5 of the Securities Exchange Act) becomes the “beneficial owner” (within the meaning of Rules 13d-3 and 13d-5 of the Securities Exchange Act), directly or indirectly, of more than 50% of the outstanding shares of

4

common stock of El Paso entitled to vote for members of the board of directors or equivalent governing body of El Paso or (b) a majority of the members of the Board of Directors of El Paso are not Continuing Directors; provided, however, that a “Change in Control” shall be deemed not to have occurred solely as a result of the formation of a holding company for El Paso as part of any transaction (merger, consolidation, plan of exchange, or otherwise) in which, immediately following such transaction, (i) such holding company owns 100% of the common stock of El Paso and (ii) such holding company is beneficially owned by the former holders of El Paso’s common stock in substantially the same proportions as their beneficial ownership of El Paso’s common stock immediately prior to such transaction.

“Change in Law” shall mean (a) the adoption of any law, rule, regulation or treaty after the date of this Agreement, (b) any change in any law, rule, regulation or treaty or in the interpretation or application thereof by any Governmental Authority after the date of this Agreement or (c) compliance by any Lender or the Issuing Bank (or, for purposes of Section 2.12(b), by any lending office of such Lender or by such Lender’s or the Issuing Bank’s holding company, if any) with any request, guideline or directive (whether or not having the force of law) of any Governmental Authority made or issued after the date of this Agreement; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Act and all requests, rules, regulations, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, regulations, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted, issued or implemented.

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Commitment” shall mean, with respect to each Lender, the commitment of such Lender to make Loans hereunder as set forth on Schedule 2.01, or in the Assignment and Acceptance pursuant to which such Lender assumed its Commitment, or, with respect to an Augmenting Lender, in the documentation executed by such Augmenting Lender pursuant to Section 2.21(a), as applicable, as the same may be (a) reduced from time to time pursuant to Section 2.09 or pursuant to Section 2.19, (b) increased (with the consent of such Lender) from time to time pursuant to Section 2.21 and (c) reduced or increased from time to time pursuant to assignments by or to such Lender pursuant to Section 10.04.

“Commitment Fee” shall have the meaning assigned to such term in Section 2.05(a).

“Continuing Directors” shall mean, as of any date of determination, any member of the board of directors of El Paso who (i) was a member of such board of directors on the Effective Date or (ii) was nominated for election or elected to such board of directors with the approval of a majority of Continuing Directors who were members of such board at the time of such nomination or election.

5

“Control” shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a person, whether through the ownership of voting securities, by contract or otherwise, and “Controlling” and “Controlled” shall have meanings correlative thereto.

“Credit Event” shall have the meaning assigned to such term in Section 4.01.

“Credit Exposure” shall mean, with respect to any Lender at any time, the aggregate principal amount at such time of all outstanding Loans of such Lender plus the aggregate amount at such time of such Lender’s L/C Exposure.

“Default” shall mean any event or condition which upon notice, lapse of time or both would constitute an Event of Default.

“Dodd-Frank Act” shall mean the Dodd-Frank Wall Street Reform and Consumer Protection Act (Public Law 111-203), as amended.

“dollars” or “$” shall mean lawful money of the United States of America.

“Domestic Subsidiary” shall mean any Subsidiary that is incorporated or organized under the laws of the United States of America, any State thereof or the District of Columbia.

“Effective Date” shall mean the date on which the conditions specified in Section 4.02 are satisfied (or waived in accordance with Section 10.08), which date is November 15, 2011.

“El Paso” shall have the meaning assigned to such term in the preamble to this Agreement.

“El Paso L/C Exposure” shall mean that part of the L/C Exposure attributable to all Letters of Credit issued for the account of El Paso.

“El Paso Obligations” shall mean (i) the due and punctual payment of (A) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding) on the Loans made to El Paso, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, (B) all monetary obligations of El Paso pursuant to the Guarantee in Article IX hereof, (C) each payment required to be made by El Paso under this Agreement in respect of any Letter of Credit, when and as due, including payments in respect of reimbursement of disbursements, interest thereon and obligations to provide cash collateral and (D) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of El Paso to the Administrative Agent and the Lenders under this Agreement and the other Loan Documents and (ii) the due and punctual performance of all

6

covenants, agreements, obligations and liabilities of El Paso under or pursuant to this Agreement and the other Loan Documents.

“Environment” shall mean ambient air, surface water and groundwater (including potable water, navigable water and wetlands), the land surface or subsurface strata, flora and fauna, natural resources or the workplace.

“Environmental Claim” shall mean any written accusation, allegation, notice of violation, claim, demand, order, directive, consent decree, cost recovery action or other cause of action by, or on behalf of, any Governmental Authority or any person for damages, injunctive or equitable relief, personal injury (including sickness, disease or death), Remedial Action costs, tangible or intangible property damage, natural resource damages, nuisance, pollution, any adverse effect on the Environment caused by any Hazardous Material, or for fines, penalties or restrictions, resulting from or based upon: (a) the existence, or the continuation of the existence, of a Release (including sudden or non-sudden, accidental or non-accidental Releases); (b) exposure to any Hazardous Material; (c) the presence, use, handling, transportation, storage, treatment or disposal of any Hazardous Material; or (d) the violation or alleged violation of any Environmental Law or Environmental Permit.

“Environmental Law” shall mean any and all applicable present and future treaties, laws, rules, regulations, codes, ordinances, orders, decrees, judgments, injunctions, notices or binding agreements issued, promulgated or entered into by any Governmental Authority, relating in any way to the Environment, preservation or reclamation of natural resources, the management, Release or threatened Release of any Hazardous Material or to health and safety matters, including but not limited to the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, 42 U.S.C. §§ 9601 etseq. (collectively “CERCLA”), the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 and Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. §§ 6901 etseq., the Federal Water Pollution Control Act, as amended by the Clean Water Act of 1977, 33 U.S.C. §§ 1251 etseq., the Clean Air Act of 1970, 42 U.S.C. §§ 7401 etseq., as amended, the Toxic Substances Control Act of 1976, 15 U.S.C. §§ 2601 etseq., the Occupational Safety and Health Act of 1970, as amended by 29 U.S.C. §§ 651 etseq., the Emergency Planning and Community Right-to-Know Act of 1986, 42 U.S.C. §§ 11001 etseq., the Safe Drinking Water Act of 1974, as amended by 42 U.S.C. §§ 300(f) etseq., the Hazardous Materials Transportation Act, 49 U.S.C. §§ 5101 etseq., the Atomic Energy Act and Low-Level Radioactive Waste Policy Act, 42 U.S.C. §§ 2014 etseq., as amended, and any similar or implementing state or local law, and all amendments or regulations promulgated thereunder.

“Environmental Permit” shall mean any permit, approval, authorization, certificate, license, variance, filing or permission required by or from any Governmental Authority pursuant to any Environmental Law.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as the same may be amended from time to time.

7

“ERISA Affiliate” shall mean any trade or business (whether or not incorporated) that, together with El Paso, is treated as a single employer under Section 414(b) or (c) of the Code, or solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

“ERISA Event” shall mean (a) any “reportable event”, as defined in Section 4043 of ERISA or the regulations issued thereunder, with respect to a Plan; (b) the adoption of any amendment to a Plan that would contravene Section 436 of the Code or Section 303 of ERISA; (c) a determination that any Plan is in “at risk” status (within the meaning of Section 430 of the Code or Section 303 of ERISA) or any Multiemployer Plan to which El Paso or any ERISA Affiliate makes or is obligated to make contributions, or during the preceding five plan years has made or been obligated to make contributions, is in “endangered status” or “critical status” within the meaning of Section 432 of the Code; (d) the failure with respect to any Plan to meet the minimum funding standards (within the meaning of Section 412 or 430 of the Code or Section 302 of ERISA), whether or not waived; (e) the filing pursuant to Section 412(c) of the Code or Section 303(c) of ERISA of an application for a waiver of the minimum funding standard with respect to any Plan; (f) the incurrence of any liability under Title IV of ERISA with respect to the termination of any Plan or the withdrawal or partial withdrawal of El Paso or any of its ERISA Affiliates from any Plan or Multiemployer Plan; (g) the receipt by El Paso or any ERISA Affiliate from the PBGC or a plan administrator of any notice relating to the intention to terminate any Plan or Plans or to appoint a trustee to administer any Plan; (h) the receipt by El Paso or any ERISA Affiliate of any notice concerning the imposition of Withdrawal Liability or a determination that a Multiemployer Plan is, or is expected to be, insolvent or in reorganization, within the meaning of Title IV of ERISA; (i) the occurrence of a “prohibited transaction” with respect to which El Paso or any of the Subsidiaries is a “disqualified person” (within the meaning of Section 4975 of the Code) or with respect to which El Paso or any such Subsidiary could otherwise be liable; and (j) any other event or condition with respect to a Plan or Multiemployer Plan that could reasonably be expected to result in liability of El Paso.

“Eurodollar Borrowing” shall mean a Borrowing comprised of Eurodollar Loans.

“Eurodollar Loan” shall mean any Loan bearing interest at a rate determined by reference to the Adjusted LIBO Rate in accordance with the provisions of Article II.

“Event of Default” shall have the meaning assigned to such term in Article VII.

“Excluded Taxes” shall mean, with respect to any payment made byany Loan Party under any Loan Document, any of the following Taxes imposed on or with respect to a Recipient: (a) Other Connection Taxes, (b) Taxes that would not have arisen but for a failure by a Non-U.S. Lender to comply with the provisions of Section 2.18(f) and (c) in the case of a Lender (other than an assignee pursuant to a request by a Borrower under Section 2.19(a)), any U.S. Federal withholding Taxes resulting from any law in effect (including FATCA) on (and, in the case of FATCA, including any regulations or official interpretations thereof issued after) the date such Lender becomes a party to this Agreement (or designates a new lending office), except to the extent that such Lender (or its assignor, if any) was entitled, at the time of designation of a

8

new lending office (or assignment), to receive additional amounts from the Borrowers with respect to such withholding Taxes pursuant to Section 2.18(a).

“Existing Credit Agreement” shall have the meaning assigned to such term in the preamble to this Agreement.

“FATCA” shall mean Sections 1471 through 1474 of the Code, as in effect on the Effective Date, and any applicable Treasury regulations promulgated thereunder or published administrative guidance implementing such Sections.

“Federal Funds Effective Rate” shall mean, for any day, the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average of the quotations for the day for such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

“Federal Power Act” shall mean the Federal Power Act of 1920, 16 U.S.C. §§ 791a etseq., and the rules and regulations promulgated thereunder, as amended from time to time.

“Fee Letter” shall mean the Fee Letter, dated November 3, 2011, between El Paso and JPMorgan, as the Administrative Agent and the Issuing Bank.

“Fees” shall mean the Commitment Fees, the Administrative Agent Fees, the L/C Participation Fees, the Upfront Fees and the Issuing Bank Fees.

“FERC” shall mean the Federal Energy Regulatory Commission, or any Governmental Authority succeeding to any or all of such Commission’s authority.

“Financial Officer” of any person shall mean the chief financial officer, principal accounting officer, treasurer, controller or other vice president with financial planning responsibilities of such person.

“First Mortgage Bonds” shall mean any series of First Mortgage Bonds of El Paso issued pursuant to a Mortgage Indenture after the Effective Date.

“GAAP” shall mean generally accepted accounting principles in the United States of America applied on a consistent basis.

“Governmental Authority” shall mean any Federal, state, local or foreign court or governmental agency, authority, instrumentality or regulatory body.

“Guarantee” of or by any person shall mean any obligation, contingent or otherwise, of such person guaranteeing or having the economic effect of guaranteeing any Indebtedness of any other person (the “primaryobligor”) in any manner, whether directly or indirectly, and including any obligation of such person, direct or indirect, (a) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness or to purchase (or

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to advance or supply funds for the purchase of) any security for the payment of such Indebtedness, (b) to purchase or lease property, securities or services for the purpose of assuring the owner of such Indebtedness of the payment of such Indebtedness or (c) to maintain working capital, equity capital or any other financial statement condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness; provided, however, that the term Guarantee shall not include endorsements for collection or deposit in the ordinary course of business.

“Hazardous Materials” shall mean all explosive or radioactive substances or wastes, hazardous or toxic substances or wastes, pollutants, solid, liquid or gaseous wastes, including petroleum or petroleum distillates, asbestos or asbestos-containing materials, polychlorinated biphenyls (“PCBs”) or PCB‑containing materials or equipment, radon gas, infectious or medical wastes and all other substances or wastes of any nature regulated pursuant to any Environmental Law.

“Increasing Lender” shall have the meaning assigned to such term in Section 2.21(a).

“Incremental Facility Amount” shall mean, at any time, the excess, if any, of (a) $100,000,000 over (b) the aggregate increase in the Total Commitment established prior to such time pursuant to Section 2.21.

“Indebtedness” of any person shall mean, without duplication, (a) all obligations of such person for borrowed money or with respect to deposits or advances of any kind, (b) all obligations of such person evidenced by bonds, debentures, notes or similar instruments, (c) all obligations of such person upon which interest charges are customarily paid, (d) all obligations of such person under conditional sale or other title retention agreements relating to property or assets purchased by such person, (e) all obligations of such person issued or assumed as the deferred purchase price of property or services (excluding trade accounts payable and accrued obligations incurred in the ordinary course of business), (f) all Indebtedness of others secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien on property owned or acquired by such person, whether or not the obligations secured thereby have been assumed, (g) all Guarantees by such person of Indebtedness of others, (h) all Capital Lease Obligations of such person, (i) all obligations of such person in respect of interest rate protection agreements, foreign currency exchange agreements or other interest or exchange rate hedging arrangements, (j) the principal component of all obligations of such person as an account party in respect of letters of credit (other than any letter of credit in respect of which a back-to-back letter of credit has been issued under, or in a transaction permitted by, this Agreement, provided that the commercial bank issuing such back-to-back letter of credit (if other than the Issuing Bank) has a long-term senior unsecured debt rating of not less than A- by S&P and not less than A3 by Moody’s) and (k) the principal component of all obligations of such person as an account party in respect of bankers’ acceptances. The Indebtedness of any person shall include the Indebtedness of any partnership in which such person is a general partner, other than to the extent that the instrument or agreement evidencing such Indebtedness expressly limits the liability of such person in respect thereof.

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“Indemnified Taxes” shall mean (a) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by any Loan Party under any Loan Document and (b) Other Taxes.

“Indemnitee” shall have the meaning assigned to such term in Section 10.05(b).

“Index Debt” shall mean the senior, unsecured, non-credit enhanced, long-term debt of El Paso.

“Interest Payment Date” shall mean, (a) with respect to any ABR Loan, the last day of each March, June, September and December, and (b) with respect to any Eurodollar Loan, the last day of the Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Eurodollar Borrowing with an Interest Period of more than three months’ duration, each day that would have been an Interest Payment Date had successive Interest Periods of three months’ duration been applicable to such Borrowing.

“Interest Period” shall mean, as to any Eurodollar Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day (or, if there is no numerically corresponding day, on the last day) in the calendar month that is 1, 2, 3 or 6 months thereafter, as the applicable Borrower may elect; provided, however, that if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case such Interest Period shall end on the next preceding Business Day. Interest shall accrue from and including the first day of an Interest Period to but excluding the last day of such Interest Period.

“IRS” shall mean the United States Internal Revenue Service.

“Issuing Bank” shall have the meaning assigned to such term in the preamble to this Agreement.

“Issuing Bank Fees” shall have the meaning assigned to such term in Section 2.05(c).

“JPMorgan” shall mean JPMorgan Chase Bank, N.A., together with its successors and assigns.

“L/C Commitment” shall mean the commitment of the Issuing Bank to issue Letters of Credit pursuant to Section 2.20.

“L/C Disbursement” shall mean a payment or disbursement made by the Issuing Bank pursuant to a Letter of Credit.

“L/C Exposure” shall mean at any time the sum of (a) the aggregate undrawn amount of all outstanding Letters of Credit at such time plus (b) the aggregate principal amount of all L/C Disbursements that have not yet been reimbursed at such time. The L/C Exposure of any Lender at any time shall mean its Applicable Percentage of the aggregate L/C Exposure at such time.

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“L/C Participation Fee” shall have the meaning assigned to such term in Section 2.05(c).

“Lenders” shall mean (a) the financial institutions listed on Schedule 2.01, (b) any financial institution that has become a party hereto pursuant to an Assignment and Acceptance and (c) any Augmenting Lender, in each case other than any such financial institution or Augmenting Lender that has ceased to be a party hereto pursuant to an Assignment and Acceptance.

“Letter of Credit” shall mean any letter of credit issued pursuant to Section 2.20.

“LIBO Rate” shall mean, with respect to any Eurodollar Borrowing for any Interest Period, the rate appearing on the Reuters Screen LIBOR01 (or on any successor or substitute screen or page of such service, or any successor to or substitute for such service, providing rate quotations comparable to those currently provided on such screen of such service, as determined by the Administrative Agent from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period, as the rate for dollar deposits with a maturity comparable to such Interest Period. In the event that such rate is not available at such time for any reason, then the “LIBO Rate” with respect to such Eurodollar Borrowing for such Interest Period shall be the rate at which dollar deposits of $5,000,000 and for a maturity comparable to such Interest Period are offered by the principal London office of the Administrative Agent in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, two Business Days prior to the commencement of such Interest Period.

“Lien” shall mean, with respect to any asset, (a) any mortgage, deed of trust, lien, pledge, encumbrance, charge or security interest in or on such asset, (b) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset and (c) in the case of securities, any purchase option, call or similar right of a third party with respect to such securities.

“Loan Documents” shall mean this Agreement, the Letters of Credit, the Fee Letter, any Notes and each Subsidiary Guarantee Agreement.

“Loan Parties” shall mean the Borrowers and the Subsidiary Guarantors.

“Loans” shall mean the loans made by the Lenders to the Borrowers pursuant to Section 2.01. Each Loan shall be a Eurodollar Loan or an ABR Loan.

“Margin Stock” shall have the meaning assigned to such term in Regulation U.

“Material Adverse Effect” shall mean (a) a materially adverse effect on the business, assets, operations or financial condition of El Paso and the Subsidiaries, taken as a whole, (b) material impairment of the ability of the Trustee, El Paso or the Subsidiary Guarantors (taken as a whole) to perform any of their respective payment or other material obligations under

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any Loan Document to which it is or will be a party or (c) material impairment of the rights of the Lenders under any Loan Document.

“Material Subsidiary”shall mean, at any time, (a) a Domestic Subsidiary of El Paso (other than a Receivables Subsidiary) with consolidated total assets at such time equal to or greater than 10% of El Paso’s consolidated total assets at such time or (b) any other Subsidiary which becomes a Subsidiary Guarantor.

“Maturity Date” shall mean September 23, 2016.

“Moody’s” shall mean Moody’s Investors Service, Inc., and its successors.

“Mortgage Indenture” shall mean any indenture (including, without limitation, any indenture entered into by El Paso following the Effective Date) secured by a mortgage Lien upon El Paso’s Operating Property.

“Multiemployer Plan” shall mean a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Non- U.S. Lender” shall mean a Lender that is not a U.S. Person.

“Note” shall have the meaning assigned to such term in Section 2.04(e).

“Nuclear Fuel” shall have the meaning assigned to such term in the Purchase Contract.

“Nuclear Waste Act” shall mean the Nuclear Waste Policy Act of 1982, 42 U.S.C. §§ 10101 etseq., the Nuclear Waste Policy Amendments Act of 1987, 42 U.S.C. §§ 10172, 10172a etseq., and the rules and regulations promulgated thereunder, as amended from time to time.

“Obligations” shall mean, collectively, the Trust Obligations and the El Paso Obligations.

“Obligation Termination Date” shall have the meaning assigned to such term in Section 12.12(a).

“Operating Property” shall mean, as of any particular time, (a) all of the real, personal and mixed property which is an integral part of or is used or to be used as an integral part of the regulated electric generating, transmission and/or distribution operations of El Paso, (b) any undivided legal interest of El Paso in any such property which is jointly owned by El Paso and any other person or persons and (c) franchises and permits owned by El Paso in connection with the regulated electric generating, transmission and/or distribution operations of El Paso, including, without limitation, all of such property which is acquired by El Paso after the Effective Date; provided, however, that Operating Property shall not be deemed to include any Operating Property excepted under a Mortgage Indenture.

“Original Closing Date” shall mean September 23, 2010.

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“Other Connection Taxes” shall mean, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Taxes (other than a connection arising solely from such Recipient having executed, delivered, enforced, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, or engaged in any other transaction pursuant to any Loan Document).

“Other Taxes” shall mean, any present or future stamp, court, documentary, intangible, recording, filing or similar excise or property Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, or from the registration, receipt or perfection of a security interest under, or otherwise with respect to, any Loan Document, except any such Taxes that are Other Connection Taxes imposed with respect to an assignment (other than an assignment under Section 2.19(a)).

“Participant Register” has the meaning assigned to such term in Section 10.04(f).

“PBGC” shall mean the Pension Benefit Guaranty Corporation referred to and defined in ERISA.

“Permitted Investments” shall mean:

(a)     direct obligations of, or obligations the principal of and interest on which are unconditionally guaranteed by, the United States of America (or by any agency thereof to the extent such obligations are backed by the full faith and credit of the United States of America), in each case maturing within one year from the date of acquisition thereof;

(b)     investments in commercial paper maturing within 270 days from the date of acquisition thereof and having, at such date of acquisition, a rating of P-1 (or higher) according to Moody’s or a rating of A-1 (or higher) according to S&P;

(c)     investments in certificates of deposit, banker’s acceptances and time deposits maturing within one year from the date of acquisition thereof issued or guaranteed by or placed with, and money market deposit accounts issued or offered by, any domestic office of any commercial bank (including the Trustee) organized under the laws of the United States of America or any state thereof which has a combined capital and surplus and undivided profits of not less than $250,000,000;

(d)     investments in obligations of United States Federal agencies sponsored by the Federal government, including the Federal Home Loan Bank, the Federal Farm Credit Bank, the Federal Home Loan Mortgage Corporation, the Federal National Mortgage Association and the Student Loan Marketing Association;

(e)     repurchase obligations with a term of not more than seven days for underlying securities of the type described in clauses (a) and (d) entered into with financial institutions which have a combined capital and surplus and undivided profits of not less than $250,000,000;

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(f)     investments in tax exempt securities, including municipal issued notes and bonds and variable-rate demand notes and bonds, having a rating at the time of acquisition thereof of at least BBB from S&P or Baa from Moody’s;

(g)     investments in corporate bonds or notes having maturities of not more than three years from the date of acquisition thereof and having a rating at the time of acquisition thereof of at least BBB from S&P or Baa from Moody’s;

(h)     investments in money market or other mutual funds substantially all of the assets of which consist of investments of the types described in clauses (a) through (g) above; and

(i)     other investment instruments approved in writing by the Required Lenders and offered by financial institutions which have a combined capital and surplus and undivided profits of not less than $250,000,000.

“person” shall mean any natural person, corporation, business trust, joint venture, association, company, limited liability company, partnership or government, or any agency or political subdivision thereof.

“Plan” shall mean any employee pension benefit plan (other than a Multiemployer Plan) subject to the provisions of Title IV of ERISA or Section 412 of the Code or Section 307 of ERISA, and in respect of which El Paso or any ERISA Affiliate is (or, if such plan were terminated, would under Section 4069 of ERISA be deemed to be) an “employer” as defined in Section 3(5) of ERISA.

“Prime Rate” shall mean the rate of interest per annum publicly announced from time to time by the Administrative Agent as its prime rate in effect at its principal office in New York City; each change in the Prime Rate shall be effective on the date such change is publicly announced as being effective.

“Purchase Contract” shall mean the Purchase Contract dated as of February 12, 1996, as amended as of February 11, 1999, July 12, 2007 and August 17, 2010, between the Trustee and El Paso, as the same may be further amended, supplemented or otherwise modified from time to time in accordance with the provisions thereof and hereof.

“Purchase Contract Default” shall have the meaning assigned to the term “Event of Default” in Section 19(a) of the Purchase Contract.

“Rating Agency” shall mean S&P and Moody’s.

“Receivables” shall have the meaning assigned to such term in the definition of “Receivables Facility”.

“Receivables Facility” shall mean one or more receivables financing facilities, as amended from time to time, the obligations in respect of which are non-recourse (except for customary representations, warranties, covenants, servicing obligations and indemnities made in connection with such facilities) to El Paso and the Subsidiaries (other than any Receivables

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Subsidiary), pursuant to which El Paso and/or any Subsidiary transfers its accounts receivable and other financial and related assets (collectively, “Receivables”) to a Receivables Subsidiary; provided, that all terms and conditions of, and all documentation relating to, a Receivables Facility shall be in form and substance customary to comparable receivables securitization facilities.

“Receivables Facility Documents” shall mean all agreements, in form and substance customary to a Receivables Facility, that may from time to time be entered into by El Paso or a Subsidiary in connection with any Receivables Facility, as such agreements may be amended, supplemented or otherwise modified from time to time in accordance with the provisions thereof and hereof.

“Receivables Subsidiary” means a wholly owned Domestic Subsidiary of El Paso formed solely for the purpose of engaging in a Receivables Facility and which acts as a purchaser of Receivables under a Receivables Facility.

“Recipient” shall mean, as applicable, (a) the Administrative Agent, (b) any Lender and (c) the Issuing Bank.

“Regional Transmission Organization” shall mean an entity that satisfies the minimum characteristics, performs the functions, and accommodates the open architecture condition set forth in FERC regulations.

“Register” shall have the meaning given such term in Section 10.04(d).

“Regulation T” shall mean Regulation T of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and all official rulings and interpretations thereunder or thereof.

“Release” shall mean any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, disposing, depositing, dispersing, emanating or migrating of any Hazardous Material in, into, onto or through the environment.

“Remedial Action” shall mean (i) “remedial action” as such term is defined in CERCLA, 42 U.S.C. § 9601(24), and (ii) all other actions required by any Governmental Authority or voluntarily undertaken to: (x) clean up, remove, treat, abate or in any other way address any Hazardous Material in the Environment; (y) prevent the Release or threat of Release, or minimize the further Release of any Hazardous Material; or (z) perform studies and investigations in connection with, or as a precondition to, (x) or (y) above.

“Required Lenders” shall mean, at any time, Lenders having Loans, L/C Exposure and unused Commitments representing more than 50% of the sum of all Loans outstanding, L/C Exposure and unused Commitments at such time.

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“Responsible Officer” of any person shall mean any executive officer or Financial Officer of such person and any other officer or similar official thereof responsible for the administration of the obligations of such person in respect of this Agreement.

“Rio Grande Resources Trust II” shall mean the trust created by the Trust Agreement.

“SEC” shall mean the Securities and Exchange Commission, or any Governmental Authority succeeding to any of its principal functions.

“Securities Act” shall mean the Securities Act of 1933, as amended from time to time.

“Securities Exchange Act” shall mean the Securities Exchange Act of 1934, as amended from time to time.

“Senior Unsecured Notes” shall mean El Paso’s (i) 6.0% Senior Notes due May 15, 2035 in an initial aggregate principal amount of $400,000,000 and (ii) 7.5% Senior Notes due March 15, 2038 in an initial aggregate principal amount of $150,000,000, in each case issued pursuant to the Indenture dated as of May 1, 2005, between El Paso and JPMorgan.

“S&P” shall mean Standard & Poor’s Rating Services and its successors.

“Specified Debt” shall have the meaning assigned to such term in Section 6.02(m).

“Statutory Reserve Rate” shall mean a fraction (expressed as a decimal), the numerator of which is the number one and the denominator of which is the number one minus the aggregate of the maximum reserve percentages (including any marginal, special, emergency or supplemental reserves) expressed as a decimal established by the Board and any other banking authority, domestic or foreign, to which the Administrative Agent or any Lender (including any branch, Affiliate, or other fronting office making or holding a Loan) is subject for eurocurrency funding (currently referred to as “Eurocurrency Liabilities” in Regulation D of the Board). Such reserve percentages shall include those imposed pursuant to such Regulation D. Eurodollar Loans shall be deemed to constitute eurocurrency funding and to be subject to such reserve requirements without benefit of or credit for proration, exemptions or offsets that may be available from time to time to any Lender under such Regulation D or any comparable regulation. The Statutory Reserve Rate shall be adjusted automatically on and as of the effective date of any change in any reserve percentage.

“Stockholders’ Equity” shall mean, as at any date of determination, the stockholders’ equity at such date of El Paso, as determined in accordance with GAAP.

“subsidiary” shall mean, with respect to any person (herein referred to as the “parent”), any corporation, partnership, association or other business entity (a) of which securities or other ownership interests representing more than 50% of the equity or more than 50% of the ordinary voting power or more than 50% of the general partnership interests are, at the time any determination is being made, owned, controlled or held, or (b) that is, at the time

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any determination is made, otherwise Controlled, by the parent or one or more subsidiaries of the parent or by the parent and one or more subsidiaries of the parent.

“Subsidiary” shall mean any subsidiary of El Paso.

“Subsidiary Guarantee Agreement” shall mean each guarantee agreement delivered pursuant to Section 5.09, each substantially in the form of Exhibit D.

“Subsidiary Guarantor” shall mean each Subsidiary that becomes a party to a Subsidiary Guarantee Agreement.

“Syndication Agent” shall have the meaning assigned to such term in the preamble to this Agreement. Notwithstanding anything contained in this Agreement to the contrary, no Lender identified as the Syndication Agent shall have any separate duties, responsibilities, obligations, authority or, except as expressly set forth in this Agreement, rights as Syndication Agent.

“Taxes” shall mean, any present or future taxes, levies, imposts, duties, deductions, withholdings, assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Total Consolidated Capital” shall mean, as at any date of determination, the sum of Total Consolidated Debt on such date and Stockholders’ Equity at such date.

“Total Commitment” shall mean, at any time, the aggregate amount of the Commitments, as in effect at such time. The Total Commitment as of the Effective Date is $200,000,000.

“Total Consolidated Debt” shall mean, as of any date of determination, all Indebtedness (other than (a) Indebtedness of the type referred to in clause (i) of the definition of the term “Indebtedness”, (b) Indebtedness of the type referred to in clause (j) of the definition of the term “Indebtedness”, except to the extent of unreimbursed drawings thereunder, and (c) Indebtedness of the type referred to in clause (k) of the definition of the term “Indebtedness”) of El Paso at such date.

“Transactions” shall have the meaning assigned to such term in Section 3.02.

“Trust Agreement” shall mean the Trust Agreement dated as of February 12, 1996, between the Trustee and El Paso, providing for the creation of the Rio Grande Resources Trust II, as the same may be amended, supplemented or otherwise modified from time to time in accordance with the provisions thereof and hereof.

“Trustee” shall have the meaning assigned to such term in the preamble to this Agreement.

“Trustee L/C Exposure” shall mean that part of the L/C Exposure attributable to all Letters of Credit issued for the account of the Trustee.

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“Trust Indenture Act” shall mean the Trust Indenture Act of 1939, and the rules and regulations promulgated thereunder, as amended from time to time.

“Trust Obligations” shall have the meaning assigned to such term in Section 9.01.

“Trust Senior Unsecured Notes” shall mean the Rio Grande Resources Trust II’s (i) 3.67% Senior Notes due August 15, 2015 in an initial aggregate principal amount of $15,000,000, (ii) 4.47% Senior Notes due August 15, 2017 in an initial aggregate principal amount of $50,000,000 and (iii) 5.04% Senior Notes due August 15, 2020 in an initial aggregate principal amount of $45,000,000, in each case issued pursuant to the Note Purchase Agreement, dated as of August 17, 2010, among El Paso, the Rio Grande Resources Trust II and the Purchasers (as defined therein) party thereto.

“Trust Termination Date” shall mean the date of any termination of the Purchase Contract.

“Type”, when used in respect of any Loan or Borrowing, shall refer to the Rate by reference to which interest on such Loan or on the Loans comprising such Borrowing is determined. For purposes hereof, the term “Rate” shall include the Adjusted LIBO Rate and the Alternate Base Rate.

“Union Bank” shall mean Union Bank, N.A., together with its successors and assigns.

“Upfront Fees” shall mean the upfront fees payable by El Paso to the Administrative Agent for the account of each Lender on the Effective Date in an amount as separately agreed by El Paso and the Administrative Agent in the Fee Letter.

“USA Patriot Act” shall mean The Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001 (Title III of Pub. L. No. 107-56 (signed into law October 26, 2001)).

“U.S. Person” shall mean a “United States person” within the meaning of Section 7701(a)(30) of the Code.

“U.S. Tax Certificate” has the meaning assigned to such term in Section 2.18(f)(ii)(D)(2).

“Wholly Owned Subsidiary” of any person (the “Parent”) shall mean a subsidiary of the Parent of which securities (except for directors’ qualifying shares) or other ownership interests representing 100% of the equity or 100% of the ordinary voting power or 100% of the general partnership interests are, at the time any determination is being made, owned, controlled or held by the Parent and/or one or more Wholly Owned Subsidiaries of the Parent.

“Withdrawal Liability” shall mean liability to a Multiemployer Plan as a result of a complete or partial withdrawal from such Multiemployer Plan, as such terms are defined in Part I of Subtitle E of Title IV of ERISA.

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“Withholding Agent” shall mean any Loan Party and the Administrative Agent.

SECTION 1.02.Terms Generally. The definitions in Section 1.01 shall apply equally to both the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. All references herein to Articles, Sections, Exhibits and Schedules shall be deemed references to Articles and Sections of, and Exhibits and Schedules to, this Agreement unless the context shall otherwise require. Except as otherwise expressly provided herein, (a) any reference in this Agreement to any Loan Document shall mean such document as amended, restated, supplemented or otherwise modified from time to time and (b) all terms of an accounting or financial nature shall be construed in accordance with GAAP, as in effect from time to time; provided, however, that, if El Paso notifies the Administrative Agent that El Paso wishes to amend any covenant in Article VI or any related definition to eliminate the effect of any change in GAAP occurring after the Effective Date on the operation of such covenant (or if the Administrative Agent notifies El Paso that the Required Lenders wish to amend Article VI or any related definition for such purpose), then El Paso’s compliance with such covenant shall be determined on the basis of GAAP in effect immediately before the relevant change in GAAP became effective, until either such notice is withdrawn or such covenant is amended in a manner satisfactory to El Paso and the Required Lenders.

ARTICLE IIThe Credits

SECTION 2.01.Commitments. Subject to the terms and conditions and relying upon the representations and warranties herein set forth, each Lender agrees, severally and not jointly, to make Loans to the Trustee or El Paso, at any time and from time to time on or after the date on which the conditions set forth in Section 4.02 are satisfied, and until the earlier of the Maturity Date and the termination of the Commitment of such Lender in accordance with the terms hereof, in an aggregate principal amount at any time outstanding that will not result in such Lender’s Credit Exposure exceeding such Lender’s Commitment. Within the limits set forth in the preceding sentence and subject to the terms, conditions and limitations set forth herein, the Borrowers may borrow, pay or prepay and reborrow Loans.

SECTION 2.02.Loans. (a) Each Loan shall be made as part of a Borrowing consisting of Loans made by the Lenders ratably in accordance with their respective Commitments; provided, however, that the failure of any Lender to make any Loan shall not in itself relieve any other Lender of its obligation to lend hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to make any Loan required to be made by such other Lender). Except for Loans deemed made pursuant to Section 2.02(f), the Loans comprising any Borrowing shall be in an aggregate principal amount that is (i)(A) with respect to any Eurodollar Borrowing, an integral multiple of $1,000,000 and not less than $5,000,000 or (B) with respect to any ABR Borrowing, an integral multiple of $1,000 and not less than $100,000 or (ii) equal to the remaining available balance of the Commitments.

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(b)Subject to Sections 2.08 and 2.13, each Borrowing shall be comprised entirely of ABR Loans or Eurodollar Loans as the applicable Borrower may request pursuant to Section 2.03. Each Lender may at its option make any Eurodollar Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan; provided that any exercise of such option shall not affect the obligation of the Borrowers to repay such Loan in accordance with the terms of this Agreement. Borrowings of more than one Type may be outstanding at the same time; provided, however, that the Borrowers shall not be entitled to request any Borrowing that, if made, would result in more than eight (8) Eurodollar Borrowings outstanding hereunder at any time. For purposes of the foregoing, Borrowings having different Interest Periods, regardless of whether they commence on the same date, shall be considered separate Borrowings.

(c)Each Lender shall make each Loan to be made by it hereunder on the proposed date thereof by wire transfer of immediately available funds to such account in New York City as the Administrative Agent may designate not later than 1:00 p.m., New York City time, and the Administrative Agent shall by 2:00 p.m., New York City time, credit the amounts so received to an account in the name of the applicable Borrower maintained with the Administrative Agent and designated by such Borrower in the applicable Borrowing Request or, if a Borrowing shall not occur on such date because any condition precedent herein specified shall not have been met, return the amounts so received to the respective Lenders.

(d)Unless the Administrative Agent shall have received notice from a Lender prior to the date of any Borrowing that such Lender will not make available to the Administrative Agent such Lender’s portion of such Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Borrowing in accordance with paragraph (c) above and the Administrative Agent may, in reliance upon such assumption, make available to the applicable Borrower on such date a corresponding amount. If the Administrative Agent shall have so made funds available then, to the extent that such Lender shall not have made such portion available to the Administrative Agent, such Lender and the applicable Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the applicable Borrower until the date such amount is repaid to the Administrative Agent at (i) in the case of either Borrower, the interest rate applicable at the time to the Loans comprising such Borrowing and (ii) in the case of such Lender, the Federal Funds Effective Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount shall constitute such Lender’s Loan as part of such Borrowing for purposes of this Agreement.

(e)Notwithstanding any other provision of this Agreement, (i) neither Borrower shall be entitled to request any Borrowing if the Interest Period requested with respect thereto would end after the Maturity Date and (ii) the Trustee shall not be entitled to request any Borrowing on or after the Trust Termination Date.

(f)If the Issuing Bank shall not have received from the Trustee or El Paso, as the case may be, the payment required to be made by Section 2.20(e) within the time specified in such Section, the Issuing Bank will promptly notify the Administrative Agent of the L/C Disbursement and the Administrative Agent will promptly notify each Lender of such L/C

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Disbursement and its Applicable Percentage thereof. Each Lender shall pay by wire transfer of immediately available funds to the Administrative Agent not later than 2:00 p.m., New York City time, on such date (or, if such Lender shall have received such notice later than 12:00 (noon), New York City time, on any day, not later than 10:00 a.m., New York City time, on the immediately following Business Day), an amount equal to such Lender’s Applicable Percentage of such L/C Disbursement (it being understood that such amount shall be deemed to constitute an ABR Loan of such Lender and such payment shall be deemed to have reduced the L/C Exposure by such amount), and the Administrative Agent will promptly pay to the Issuing Bank amounts so received by it from the Lenders. The Administrative Agent will promptly pay to the Issuing Bank any amounts received by it from the Trustee or El Paso, as the case may be, pursuant to Section 2.20(e) prior to the time that any Lender makes any payment pursuant to this paragraph (f); any such amounts received by the Administrative Agent thereafter will be promptly remitted by the Administrative Agent to the Lenders that shall have made such payments and to the Issuing Bank, as their interests may appear. If any Lender shall not have made its Applicable Percentage of such L/C Disbursement available to the Administrative Agent as provided above, such Lender and the Trustee or El Paso, as the case may be, severally agree to pay interest on such amount, for each day from and including the date such amount is required to be paid in accordance with this paragraph to but excluding the date such amount is paid, to the Administrative Agent at (i) in the case of the Trustee or El Paso, as the case may be, a rate per annum equal to the interest rate applicable to ABR Loans pursuant to Section 2.06(a), and (ii) in the case of such Lender, for the first such day, the Federal Funds Effective Rate, and for each day thereafter, the Alternate Base Rate.

SECTION 2.03.Borrowing Procedure. In order to request a Borrowing (other than a deemed Borrowing pursuant to Section 2.02(f), as to which this Section 2.03 shall not apply), the applicable Borrower shall hand deliver or telecopy to the Administrative Agent a duly completed Borrowing Request (a) in the case of a Eurodollar Borrowing, not later than 11:00 a.m., New York City time, three Business Days before a proposed Borrowing, and (b) in the case of an ABR Borrowing, not later than 12:00 noon, New York City time, on the day of the proposed Borrowing. Each Borrowing Request shall be irrevocable, shall be signed by or on behalf of the applicable Borrower and shall specify the following information: (i) whether the Borrowing then being requested is to be a Eurodollar Borrowing or an ABR Borrowing; (ii) the date of such Borrowing (which shall be a Business Day); (iii) the number and location of the account to which funds are to be disbursed (which shall be an account that complies with the requirements of Section 2.02(c)); (iv) the amount of such Borrowing; and (v) if such Borrowing is to be a Eurodollar Borrowing, the Interest Period with respect thereto; provided, however, that, notwithstanding any contrary specification in any Borrowing Request, each requested Borrowing shall comply with the requirements set forth in Section 2.02. If no election as to the Type of Borrowing is specified in any such notice, then the requested Borrowing shall be an ABR Borrowing. If no Interest Period with respect to any Eurodollar Borrowing is specified in any such notice, then the applicable Borrower shall be deemed to have selected an Interest Period of one month’s duration. The Administrative Agent shall promptly advise the Lenders of any notice given pursuant to this Section 2.03 (and the contents thereof), and of each Lender’s portion of the requested Borrowing.

SECTION 2.04.Evidence of Debt; Repayment of Loans. (a) Each Borrower hereby unconditionally promises to pay to the Administrative Agent for the account of each

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Lender the then unpaid principal amount of each Loan made to such Borrower on the Maturity Date; provided, however, that if the Purchase Contract shall terminate prior to the Maturity Date, the Trustee shall repay the unpaid principal amount of each Loan made to it on the earlier of (i) the Maturity Date, (ii) the 150th day following the Trust Termination Date, (iii) if any Event of Default that is not a Purchase Contract Default shall be in existence on the Trust Termination Date or shall thereafter occur, the 10th day following the later to occur of the Trust Termination Date or such Event of Default or (iv) if a Purchase Contract Default shall have occurred, on (A) the date of such occurrence or (B) such later date as the Administrative Agent may elect.

(b)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Loan made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time under this Agreement.

(c)The Administrative Agent shall maintain accounts in which it will record (i) the amount of each Loan made hereunder, the Type thereof and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from each Borrower to each Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from each Borrower and each Lender’s share thereof.

(d)The entries made in the accounts maintained pursuant to paragraphs (b) and (c) above shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such accounts or any error therein shall not in any manner affect the obligations of the Borrowers to repay the Loans in accordance with their terms.

(e)Notwithstanding any other provision of this Agreement, in the event any Lender shall request and receive a promissory note payable to such Lender and its registered assigns (each, a “Note”), the interests represented by such Note shall at all times (including after any assignment of all or part of such interests pursuant to Section 10.04) be represented by one or more Notes payable to the payee named therein or its registered assigns.

SECTION 2.05.Fees. (a) The Borrowers agree, jointly and severally, to pay to each Lender, through the Administrative Agent, on the last day of March, June, September and December in each year and on each date on which the Commitment of such Lender shall expire or be terminated as provided herein, a commitment fee (a “Commitment Fee”) equal to the Applicable Spread per annum in effect from time to time on the daily unused amount of the Commitment of such Lender during the preceding quarter (or other period commencing on the Original Closing Date or ending on the Maturity Date or the date on which the Commitments of such Lender shall expire or be terminated). All Commitment Fees shall be computed on the basis of the actual number of days elapsed in a year of 360 days. The Commitment Fees due to each Lender shall commence to accrue on the Original Closing Date and shall cease to accrue on the date on which the Commitment of such Lender shall expire or be terminated as provided herein.

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(b)The Borrowers agree, jointly and severally, to pay to the Administrative Agent the fees set forth in the Fee Letter at the times and in the amounts specified therein (the “Administrative Agent Fees”).

(c)The Borrowers agree, jointly and severally, to pay (i) to each Lender, through the Administrative Agent, on the last day of March, June, September and December of each year and on the date on which the Commitment of such Lender shall be terminated as provided herein, a fee (an “L/C Participation Fee”) calculated on such Lender’s Applicable Percentage of the daily aggregate L/C Exposure (excluding the portion thereof attributable to unreimbursed L/C Disbursements) during the preceding quarter (or shorter period commencing on the Original Closing Date or ending on the Maturity Date or the date on which all Letters of Credit have been canceled or have expired and the Commitments of all Lenders shall have been terminated) at a rate per annum equal to the Applicable Spread from time to time used to determine the interest rate on Eurodollar Loans pursuant to Section 2.06(b) and (ii) to the Issuing Bank with respect to each Letter of Credit the fronting fees set forth in the Fee Letter (the “Issuing Bank Fees”). All L/C Participation Fees and Issuing Bank Fees shall be computed on the basis of the actual number of days elapsed in a year of 360 days.

(d)All Fees shall be paid on the dates due, in immediately available funds, to the Administrative Agent for distribution, if and as appropriate, among the Lenders, except that the Issuing Bank Fees shall be paid directly to the Issuing Bank. Once paid, none of the Fees shall be refundable under any circumstances.

SECTION 2.06.Interest on Loans. (a) Subject to the provisions of Section 2.07, the Loans comprising each ABR Borrowing shall bear interest (computed on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be, when the Alternate Base Rate is determined by reference to the Prime Rate and over a year of 360 days at all other times) at a rate per annum equal to the Alternate Base Rate plus the Applicable Spread in effect from time to time.

(b)Subject to the provisions of Section 2.07, the Loans comprising each Eurodollar Borrowing shall bear interest (computed on the basis of the actual number of days elapsed over a year of 360 days) at a rate per annum equal to the Adjusted LIBO Rate for the Interest Period in effect for such Borrowing plus the Applicable Spread in effect from time to time.

(c)Interest on each Loan shall be payable on the Interest Payment Dates applicable to such Loan except as otherwise provided in this Agreement. The applicable Alternate Base Rate, Adjusted LIBO Rate and Applicable Spread for each Interest Period or day within an Interest Period, as the case may be, shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

SECTION 2.07.Default Interest. If either Borrower shall default in the payment of the principal of or interest on any Loan or any other amount becoming due hereunder, by acceleration or otherwise, or under any other Loan Document, such Borrower shall on demand from time to time pay interest, to the extent permitted by law, on such defaulted amount to but excluding the date of actual payment (after as well as before judgment) (a) in the case of overdue

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principal, at the rate otherwise applicable to such Loan pursuant to Section 2.06 plus 2.00% per annum and (b) in all other cases, at a rate per annum (computed on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be, when determined by reference to the Prime Rate and over a year of 360 days at all other times) equal to the sum of the Alternate Base Rate plus the Applicable Spread in effect from time to time plus 2.00%.

SECTION 2.08.Alternate Rate of Interest. In the event, and on each occasion, that on the day two Business Days prior to the commencement of any Interest Period for a Eurodollar Borrowing the Administrative Agent shall have determined that dollar deposits in the principal amounts of the Loans comprising such Borrowing are not generally available in the London interbank market, or that the rates at which such dollar deposits are being offered will not adequately and fairly reflect the cost to any Lender of making or maintaining its Eurodollar Loan during such Interest Period, or that reasonable means do not exist for ascertaining the LIBO Rate, the Administrative Agent shall, as soon as practicable thereafter, give written or facsimile notice of such determination to the Borrowers and the Lenders. In the event of any such determination, until the Administrative Agent shall have advised the Borrowers and the Lenders that the circumstances giving rise to such notice no longer exist, any request by either Borrower for a Eurodollar Borrowing pursuant to Section 2.03 shall be deemed to be a request for an ABR Borrowing. Each determination by the Administrative Agent hereunder shall be conclusive absent manifest error.

SECTION 2.09.Termination and Reduction of Commitments. (a) The Commitments and the L/C Commitment shall automatically terminate on the Maturity Date.

(b)Upon at least three Business Days’ prior irrevocable written or facsimile notice to the Administrative Agent, the Borrowers may at any time in whole permanently terminate, or from time to time in part permanently reduce, the Commitments; provided, however, that (i) each partial reduction of the Commitments shall be in an integral multiple of $1,000,000 and in a minimum amount of $5,000,000 and (ii) the Total Commitment shall not be reduced to an amount that is less than the Aggregate Credit Exposure at the time; provided that a notice of termination of the Commitments delivered by the Borrowers may state that such notice is conditioned upon the effectiveness of other credit facilities or debt financing (such notice to specify the proposed effective date), in which case such notice may be revoked by the Borrowers (by notice to the Administrative Agent on or prior to such specified effective date) if such condition is not satisfied and the Borrowers shall indemnify the Lenders in accordance with Section 2.14 in connection therewith.

(c)Each reduction in the Commitments hereunder shall be made ratably among the Lenders in accordance with their respective Commitments. The Borrowers shall pay to the Administrative Agent for the account of the applicable Lenders, on the date of each termination or reduction, the Commitment Fees on the amount of the Commitments so terminated or reduced accrued to but excluding the date of such termination or reduction.

SECTION 2.10.Conversion and Continuation of Borrowings. The applicable Borrower shall have the right at any time upon prior irrevocable notice to the Administrative Agent (a) not later than 12:00 (noon), New York City time, one Business Day prior to conversion, to convert any Eurodollar Borrowing into an ABR Borrowing, (b) not later than

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11:00 a.m., New York City time, three Business Days prior to conversion or continuation, to convert any ABR Borrowing into a Eurodollar Borrowing or to continue any Eurodollar Borrowing as a Eurodollar Borrowing for an additional Interest Period, and (c) not later than 11:00 a.m., New York City time, three Business Days prior to conversion, to convert the Interest Period with respect to any Eurodollar Borrowing to another permissible Interest Period, subject in each case to the following:

(i)each conversion or continuation shall be made pro rata among the Lenders in accordance with the respective principal amounts of the Loans comprising the converted or continued Borrowing;

(ii)if less than all the outstanding principal amount of any Borrowing shall be converted or continued, then each resulting Borrowing shall satisfy the limitations specified in Sections 2.02(a) and 2.02(b) regarding the principal amount and maximum number of Borrowings of the relevant Type;

(iii)each conversion shall be effected by each Lender and the Administrative Agent by recording for the account of such Lender the new Loan of such Lender resulting from such conversion and reducing the Loan (or portion thereof) of such Lender being converted by an equivalent principal amount; accrued interest on any Eurodollar Loan (or portion thereof) being converted shall be paid by such Borrower at the time of conversion;

(iv)if any Eurodollar Borrowing is converted at a time other than the end of the Interest Period applicable thereto, such Borrower shall pay, upon demand, any amounts due to the Lenders pursuant to Section 2.14;

(v)any portion of a Borrowing maturing in less than one month may not be converted into or continued as a Eurodollar Borrowing;

(vi)any portion of a Eurodollar Borrowing that cannot be converted into or continued as a Eurodollar Borrowing by reason of the immediately preceding clause shall be automatically converted at the end of the Interest Period in effect for such Borrowing into an ABR Borrowing; and

(vii)upon notice to the Borrowers from the Administrative Agent given at the request of the Required Lenders, after the occurrence and during the continuance of a Default or Event of Default, no outstanding Loan may be converted into, or continued as, a Eurodollar Loan.

Each notice pursuant to this Section 2.10 shall be irrevocable and shall refer to this Agreement and specify (A) the identity and amount of the Borrowing that the applicable Borrower requests be converted or continued, (B) whether such Borrowing is to be converted to or continued as a Eurodollar Borrowing or an ABR Borrowing, (C) if such notice requests a conversion, the date of such conversion (which shall be a Business Day) and (D) if such Borrowing is to be converted to or continued as a Eurodollar Borrowing, the Interest Period with respect thereto. If no Interest Period is specified in any such notice with respect to any conversion to or continuation as a Eurodollar Borrowing, the applicable Borrower shall be

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deemed to have selected an Interest Period of one month’s duration. The Administrative Agent shall advise the Lenders of any notice given pursuant to this Section 2.10 and of each Lender’s portion of any converted or continued Borrowing. If a Borrower shall not have given notice in accordance with this Section 2.10 to continue any Borrowing into a subsequent Interest Period (and shall not otherwise have given notice in accordance with this Section 2.10 to convert such Borrowing), such Borrowing shall, at the end of the Interest Period applicable thereto (unless repaid pursuant to the terms hereof), automatically be continued into an ABR Borrowing.

SECTION 2.11.Optional Prepayment. (a) Each Borrower shall have the right at any time and from time to time to prepay any Borrowing, in whole or in part, upon written or facsimile notice (or telephone notice promptly confirmed by written or facsimile notice) to the Administrative Agent before 12:00 (noon), New York City time (i) in the case of any prepayment of a Eurodollar Borrowing, at least three Business Days prior to the date designated for such prepayment or (ii) in the case of any prepayment of an ABR Borrowing, on the date of such prepayment; provided, however, that each partial prepayment shall be in an amount that is (x) in the case of any partial prepayment of a Eurodollar Borrowing, an integral multiple of $1,000,000 and not less than $5,000,000 or (y) in the case of any partial prepayment of an ABR Borrowing, an integral multiple of $1,000 and not less than $100,000.

(b)In the event of a termination of all the Commitments, each Borrower shall repay or prepay all of its outstanding Borrowings on the date of such termination, together with accrued interest to but excluding the date of such payment. In the event of any partial reduction of the Commitments, then (i) at or prior to the effective date of such reduction or termination, the Administrative Agent shall notify the Borrowers and the Lenders of the Aggregate Credit Exposure after giving effect thereto and (ii) if the Aggregate Credit Exposure would exceed the Total Commitment after giving effect to such reduction or termination, then the Borrowers shall, on the date of such reduction or termination, repay or prepay Borrowings in an amount sufficient to eliminate such excess.

(c)Each notice of prepayment shall specify the prepayment date and the principal amount of each Borrowing (or portion thereof) to be prepaid, shall be irrevocable and shall commit the applicable Borrower to prepay such Borrowing by the amount stated therein on the date stated therein. All prepayments under this Section 2.11 shall be subject to Section 2.14 but otherwise without premium or penalty. All prepayments under this Section 2.11 (other than prepayments of ABR Loans prior to the Maturity Date) shall be accompanied by accrued interest on the principal amount being prepaid to but excluding the date of payment.

SECTION 2.12.Reserve Requirements; Change in Circumstances. (a) Notwithstanding any other provision of this Agreement, if after the date of this Agreement, but prior to the first date on which the events described in clauses (A), (B), (C) and (D) of subsection (d) of this Section 2.12 shall have occurred (the “ObligationTerminationDate”), any Change in Law shall impose, modify or deem applicable any reserve, special deposit or similar requirement against assets of, deposits with or for the account of or credit extended by any Lender or the Issuing Bank or shall impose on such Lender or the Issuing Bank or the London interbank market any other condition affecting this Agreement or Eurodollar Loans made by such Lender or any Letter of Credit or participation therein or subject any Recipient to any Taxes (other than (i) Taxes imposed on or with respect to any payment made by any Loan Party under

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any Loan Document, which shall be solely governed by Section 2.18, (ii) Other Taxes, and (iii) Other Connection Taxes on gross or net income, profits or receipts (including value-added or similar Taxes, franchise Taxes and branch profits Taxes)) on its loans, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto, and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making or maintaining any Eurodollar Loan or increase the cost to any Lender, the Issuing Bank or such other Recipient of issuing or maintaining any Letter of Credit or purchasing or maintaining a participation therein or to reduce the amount of any sum received or receivable by such Lender, the Issuing Bank or such other Recipient (whether of principal, interest or otherwise) by an amount deemed by such Lender, the Issuing Bank or such other Recipient to be material, then the applicable Borrower will pay to such Lender, the Issuing Bank or such other Recipient, as the case may be, upon demand such additional amount or amounts as will compensate such Lender, the Issuing Bank or such other Recipient, as the case may be, for such additional costs incurred or reduction suffered.

(b)If any Lender or the Issuing Bank shall have determined that the adoption after the Effective Date, but prior to the Obligation Termination Date, of any law, rule, regulation, agreement or guideline regarding capital adequacy, or any change after the Effective Date, but prior to the Obligation Termination Date, in any such law, rule, regulation, agreement or guideline (whether such law, rule, regulation, agreement or guideline has been adopted) or in the interpretation or administration thereof by any Governmental Authority charged with the interpretation or administration thereof, or compliance by any Lender (or any lending office of such Lender) or the Issuing Bank or any Lender’s or the Issuing Bank’s holding company with any request or directive regarding capital adequacy (whether or not having the force of law) of any Governmental Authority has or would have the effect of reducing the rate of return on such Lender’s or the Issuing Bank’s capital or on the capital of such Lender’s or the Issuing Bank’s holding company, if any, as a consequence of this Agreement or the Loans made or participation in Letters of Credit purchased by such Lender pursuant hereto or the Letters of Credit issued by the Issuing Bank pursuant hereto to a level below that which such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company could have achieved but for such applicability, adoption, change or compliance (taking into consideration such Lender’s or the Issuing Bank’s policies and the policies of such Lender’s or the Issuing Bank’s holding company with respect to capital adequacy) by an amount deemed by such Lender or the Issuing Bank to be material, then from time to time the applicable Borrower shall pay to such Lender or the Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or the Issuing Bank or such Lender’s or the Issuing Bank’s holding company for any such reduction suffered. For the avoidance of doubt and notwithstanding anything herein to the contrary, this Section 2.12(b) shall apply to (x) the Dodd-Frank Act and all requests, rules, regulations, guidelines or directives thereunder or issued in connection therewith concerning capital adequacy and (y) all requests, rules, regulations, guidelines or directives concerning capital adequacy promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, regardless of the date enacted, adopted, issued or implemented.

(c)A certificate of a Lender or the Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or the Issuing Bank or its holding company, as

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applicable, as specified in paragraph (a) or (b) above shall be delivered to the applicable Borrower and shall be conclusive absent manifest error. The applicable Borrower shall pay such Lender or the Issuing Bank the amount shown as due on any such certificate delivered by it within 30 days after its receipt of the same.

(d)Failure or delay on the part of any Lender or the Issuing Bank to demand compensation for any increased costs or reduction in amounts received or receivable or reduction in return on capital shall not constitute a waiver of such Lender’s or the Issuing Bank’s right to demand such compensation under this Section 2.12 for any costs incurred or reduction suffered with respect to any date so long as such Lender or the Issuing Bank, as applicable, shall have notified the applicable Borrower that it will demand compensation for such costs or reduction under paragraph (c) above, not more than 90 days after the later of (i) such date and (ii) the date on which such Lender or the Issuing Bank, as applicable, shall have become aware of such costs or reduction. Notwithstanding the foregoing, no notification contemplated by the preceding sentence shall in any event be made more than 30 days after the date that (A) all the Obligations have been indefeasibly paid in full, (B) the Lenders have no further commitment to lend to either of the Borrowers under this Agreement, (C) the L/C Exposure has been reduced to zero and (D) the Issuing Bank has no further obligation to issue Letters of Credit under this Agreement. The protection of this Section 2.12 shall be available to each Lender and the Issuing Bank regardless of any possible contention of the invalidity or inapplicability of the law, rule, regulation, agreement, guideline or other change or condition that shall have occurred or been imposed.

SECTION 2.13.Change in Legality. (a) Notwithstanding any other provision of this Agreement, if, after the date hereof, any Change in Law shall make it unlawful for any Lender to make or maintain any Eurodollar Loan or to give effect to its obligations as contemplated hereby with respect to any Eurodollar Loan, then, by written notice to the Borrowers and to the Administrative Agent:

(i)such Lender may declare that Eurodollar Loans will not thereafter (for the duration of such unlawfulness) be made by such Lender hereunder (or be continued for additional Interest Periods) and ABR Loans will not thereafter (for such duration) be converted into Eurodollar Loans, whereupon any request for a Eurodollar Borrowing (or to convert an ABR Borrowing to a Eurodollar Borrowing or to continue a Eurodollar Borrowing for an additional Interest Period) shall, as to such Lender only, be deemed a request for an ABR Loan (or a request to continue an ABR Loan as such or to convert a Eurodollar Loan into an ABR Loan, as the case may be), unless such declaration shall be subsequently withdrawn; and

(ii)such Lender may require that all outstanding Eurodollar Loans made by it be converted to ABR Loans, in which event all such Eurodollar Loans shall be automatically converted to ABR Loans as of the effective date of such notice as provided in paragraph (b) below.

In the event any Lender shall exercise its rights under (i) or (ii) above, all payments and prepayments of principal that would otherwise have been applied to repay the Eurodollar Loans that would have been made by such Lender or the converted Eurodollar Loans

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of such Lender shall instead be applied to repay the ABR Loans made by such Lender in lieu of, or resulting from the conversion of, such Eurodollar Loans.

(b)For purposes of this Section 2.13, a notice to the Borrowers by any Lender shall be effective as to each Eurodollar Loan made by such Lender, if lawful, on the last day of the Interest Period currently applicable to such Eurodollar Loan; in all other cases such notice shall be effective on the date of receipt by the Borrowers.

SECTION 2.14.Indemnity. Each Borrower shall indemnify each Lender against any loss or expense that such Lender may sustain or incur as a consequence of (a) any event, other than a default by such Lender in the performance of its obligations hereunder, which results in (i) such Lender receiving or being deemed to receive any amount on account of the principal of any Eurodollar Loan to such Borrower prior to the end of the Interest Period in effect therefor, (ii) the conversion of any Eurodollar Loan to such Borrower to an ABR Loan, or the conversion of the Interest Period with respect to any Eurodollar Loan to such Borrower, in each case other than on the last day of the Interest Period in effect therefor, or (iii) any Eurodollar Loan to be made by such Lender to such Borrower (including any Eurodollar Loan to be made pursuant to a conversion or continuation under Section 2.10) not being made after notice of such Loan shall have been given by such Borrower hereunder (any of the events referred to in this clause (a) being called a “Breakage Event”) or (b) any default by such Borrower in the making of any payment or prepayment required to be made hereunder. In the case of any Breakage Event, such loss shall include an amount equal to the excess, as reasonably determined by such Lender, of (i) its cost of obtaining funds for the Eurodollar Loan that is the subject of such Breakage Event for the period from the date of such Breakage Event to the last day of the Interest Period in effect (or that would have been in effect) for such Loan over (ii) the amount of interest likely to be realized by such Lender in redeploying the funds released or not utilized by reason of such Breakage Event for such period. A certificate of any Lender setting forth any amount or amounts which such Lender is entitled to receive pursuant to this Section 2.14 shall be delivered to the applicable Borrower and shall be conclusive absent manifest error.

SECTION 2.15.Pro Rata Treatment. Except as required under Section 2.13, each Borrowing, each payment or prepayment of principal of any Borrowing, each payment of interest on the Loans, each payment of the Commitment Fees and the L/C Participation Fees, each reduction of the Commitments and each conversion of any Borrowing to or continuation of any Borrowing as a Borrowing of any Type shall be allocated pro rata among the Lenders in accordance with their respective applicable Commitments (or, if such Commitments shall have expired or been terminated, in accordance with the respective principal amounts of their outstanding Loans). Each Lender agrees that in computing such Lender’s portion of any Borrowing to be made hereunder, the Administrative Agent may, in its discretion, round each Lender’s percentage of such Borrowing to the next higher or lower whole dollar amount.

SECTION 2.16.Sharing of Setoffs. Each Lender agrees that if it shall, through the exercise of a right of banker’s lien, setoff or counterclaim against either Borrower, or pursuant to a secured claim under Section 506 of Title 11 of the United States Code or other security or interest arising from, or in lieu of, such secured claim, received by such Lender under any applicable bankruptcy, insolvency or other similar law or otherwise, or by any other means, obtain payment (voluntary or involuntary) in respect of any Loan or Loans or L/C Disbursement

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as a result of which the unpaid principal portion of its Loans and participation in L/C Disbursements shall be proportionately less than the unpaid principal portion of the Loans and participation in L/C Disbursements of any other Lender, it shall be deemed simultaneously to have purchased from such other Lender at face value, and shall promptly pay to such other Lender the purchase price for, a participation in the Loans and L/C Exposure of such other Lender, so that the aggregate unpaid principal amount of the Loans and L/C Exposure and participation in Loans and L/C Exposure held by each Lender shall be in the same proportion to the aggregate unpaid principal amount of all Loans and L/C Exposure then outstanding as the principal amount of its Loans and L/C Exposure prior to such exercise of banker’s lien, setoff or counterclaim or other event was to the principal amount of all Loans and L/C Exposure outstanding prior to such exercise of banker’s lien, setoff or counterclaim or other event; provided, however, that if any such purchase or purchases or adjustments shall be made pursuant to this Section 2.16 and the payment giving rise thereto shall thereafter be recovered, such purchase or purchases or adjustments shall be rescinded to the extent of such recovery and the purchase price or prices or adjustment restored without interest. Each Borrower expressly consents to the foregoing arrangements and agrees that any Lender holding a participation in a Loan or L/C Disbursement deemed to have been so purchased may exercise any and all rights of banker’s lien, setoff or counterclaim with respect to any and all moneys owing by such Borrower to such Lender by reason thereof as fully as if such Lender had made a Loan directly to such Borrower in the amount of such participation.

SECTION 2.17.Payments. (a) Each Borrower shall make each payment (including principal of or interest on any Borrowing or any L/C Disbursement or any Fees or other amounts) hereunder and under any other Loan Document not later than 2:00 p.m., New York City time, on the date when due in immediately available dollars, without setoff, defense or counterclaim. Each such payment (other than Issuing Bank Fees, which shall be paid directly to the Issuing Bank if other than the Administrative Agent) shall be made to the Administrative Agent at its offices at 1111 Fannin Street, 10th Floor, Houston, TX 77002. Notwithstanding the foregoing, each request by El Paso or the Administrative Agent to the Trustee for a payment under this Agreement must be by an authorized officer of the requesting party and must contain wire instructions for the account to which that payment is to be made.

(b)Whenever any payment (including principal of or interest on any Borrowing or any Fees or other amounts) hereunder or under any other Loan Document shall become due, or otherwise would occur, on a day that is not a Business Day, such payment may be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of interest or Fees, if applicable.

SECTION 2.18.Taxes. (a) Withholding of Taxes; Gross-Up. Each payment by any Loan Party under the Loan Documents shall be made without withholding for any Taxes, unless such withholding is required by any law. If any Withholding Agent determines, in its sole discretion exercised in good faith, that it is so required to withhold Taxes, then such Withholding Agent may so withhold and shall timely pay the full amount of withheld Taxes to the relevant Governmental Authority in accordance with applicable law. If such Taxes are Indemnified Taxes, then the amount payable by such Loan Party shall be increased as necessary so that, net of such withholding (including such withholding applicable to additional amounts payable under

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this Section), the applicable Recipient receives the amount it would have received had no such withholding been made.

(b)Payment of Other Taxes by the Borrower. The Borrowers shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c)Evidence of Payments. As soon as practicable after any payment of Indemnified Taxes by any Loan Party to a Governmental Authority, such Loan Party shall deliver to the Administrative Agent the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(d)Indemnification by the Borrowers. The Borrowers shall jointly and severally indemnify each Recipient for any Indemnified Taxes that are paid or payable by such Recipient in connection with any Loan Document (including Indemnified Taxes with respect to amounts paid or payable under this Section 2.18(d)) and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The indemnity under this Section 2.18(d) shall be paid within 15 days after the Recipient delivers to any Borrower a certificate stating the amount of any Indemnified Taxes so paid or payable by such Recipient. Such certificate shall be conclusive of the amount so paid or payable absent manifest error. Such Recipient shall deliver a copy of such certificate to the Administrative Agent.

(e)Indemnification by the Lenders. Each Lender shall severally indemnify the Administrative Agent for any Taxes (but, in the case of any Indemnified Taxes, only to the extent that any Loan Party has not already indemnified the Administrative Agent for such Indemnified Taxes and without limiting the obligation of the Loan Parties to do so) attributable to such Lender that are paid or payable by the Administrative Agent in connection with any Loan Document and any reasonable expenses arising therefrom or with respect thereto, whether or not such Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. The indemnity under this Section 2.18(e) shall be paid within 10 days after the Administrative Agent delivers to the applicable Lender a certificate stating the amount of Taxes so paid or payable by the Administrative Agent. Such certificate shall be conclusive of the amount so paid or payable absent manifest error.

(f)Status of Lenders. (i) Any Lender that is entitled to an exemption from, or reduction of, any applicable withholding Tax with respect to any payments under any Loan Document shall deliver to the Borrowers and the Administrative Agent, at the time or times reasonably requested by the Borrowers or the Administrative Agent, such properly completed and executed documentation reasonably requested by the Borrowers or the Administrative Agent as will permit such payments to be made without, or at a reduced rate of, withholding. In addition, any Lender, if requested by the Borrowers or the Administrative Agent, shall deliver such other documentation prescribed by law or reasonably requested by the Borrowers or the Administrative Agent as will enable the Borrowers or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Notwithstanding anything to the contrary in the preceding two sentences, the completion, execution and submission of such documentation (other than such documentation set

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forth in Section 2.18(f)(ii) and (iii) below) shall not be required if in the Lender’s reasonable judgment such completion, execution or submission would subject such Lender to any material unreimbursed cost or expense or would materially prejudice the legal or commercial position of such Lender. Upon the reasonable request of a Borrower or the Administrative Agent, any Lender shall update any form or certification previously delivered pursuant to this Section 2.18(f). If any form or certification previously delivered pursuant to this Section expires or becomes obsolete or inaccurate in any respect with respect to a Lender, such Lender shall promptly (and in any event within 10 days after such expiration, obsolescence or inaccuracy) notify the Borrowers and the Administrative Agent in writing of such expiration, obsolescence or inaccuracy and update the form or certification if it is legally eligible to do so.

(ii)Without limiting the generality of the foregoing, each Lender shall, if it is legally eligible to do so, deliver to the Borrowers and the Administrative Agent (in such number of copies reasonably requested by the Borrowers and the Administrative Agent) on or prior to the date on which such Lender becomes a party hereto, duly completed and executed copies of whichever of the following is applicable:

(A)    in the case of a Lender that is a U.S. Person, IRS Form W-9 certifying that such Lender is exempt from U.S. Federal backup withholding tax;

(B)    in the case of a Non-U.S. Lender claiming the benefits of an income tax treaty to which the United States is a party (1) with respect to payments of interest under any Loan Document, IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. Federal withholding Tax pursuant to the “interest” article of such tax treaty and (2) with respect to any other applicable payments under this Agreement, IRS Form W-8BEN establishing an exemption from, or reduction of, U.S. Federal withholding Tax pursuant to the “business profits” or “other income” article of such tax treaty;

(C)     in the case of a Non-U.S. Lender for whom payments under this Agreement constitute income that is includible in gross income for U.S. federal income tax purposes because it is effectively connected with such Lender’s conduct of a trade or business in the United States, IRS Form W-8ECI;

(D)     in the case of a Non-U.S. Lender claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code both (1) IRS Form W-8BEN and (2) a certificate (a “U.S. Tax Certificate”) to the effect that such Lender is not (a) a “bank” within the meaning of Section 881(c)(3)(A) of the Code, (b) a “10 percent shareholder” of either Borrower within the meaning of Section 881(c)(3)(B) of the Code (c) a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code and (d) conducting a trade or business in the United States with which the relevant interest payments are effectively connected (or the interest payments are effectively connected but are not includible in the Non-U.S. Lender’s gross income for U.S. federal income tax purposes under an income tax treaty);

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(E)     in the case of a Non-U.S. Lender that is not the beneficial owner of payments made under this Agreement (including a partnership or a participating Lender) (1) an IRS Form W-8IMY on behalf of itself and (2) the relevant forms prescribed in clauses (A), (B), (C), (D) and (F) of this paragraph (f)(ii) that would be required of each such beneficial owner or partner of such partnership if such beneficial owner or partner were a Lender; provided, however, that if the Lender is a partnership and one or more of its partners are claiming the exemption for portfolio interest under Section 881(c) of the Code, such Lender may provide a U.S. Tax Certificate on behalf of such partners; or

(F)     any other form prescribed by law as a basis for claiming exemption from, or a reduction of, U.S. Federal withholding Tax together with such supplementary documentation necessary to enable the Borrowers or the Administrative Agent to determine the amount of Tax (if any) required by law to be withheld.

(iii)If a payment made to a Lender under any Loan Document would be subject to U.S. Federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to the Withholding Agent, at the time or times prescribed by law and at such time or times reasonably requested by the Withholding Agent, such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Withholding Agent as may be necessary for the Withholding Agent to comply with its obligations under FATCA, to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.

(g)Treatment of Certain Refunds. If any party determines, in its sole discretion exercised in good faith, that it has received a refund of any Taxes as to which it has been indemnified pursuant to this Section 2.18 (including additional amounts paid pursuant to this Section 2.18), it shall pay to the indemnifying party an amount equal to such refund (but only to the extent of indemnity payments made under this Section with respect to the Taxes giving rise to such refund), net of all out-of-pocket expenses (including any Taxes) of such indemnified party and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund). Such indemnifying party, upon the request of such indemnified party, shall repay to such indemnified party the amount paid to such indemnified party pursuant to the previous sentence (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) in the event such indemnified party is required to repay such refund to such Governmental Authority. Notwithstanding anything to the contrary in this Section 2.18(g), in no event will any indemnified party be required to pay any amount to any indemnifying party pursuant to this Section 2.18(g) if such payment would place such indemnified party in a less favorable position (on a net after-Tax basis) than such indemnified party would have been in if the indemnification payments or additional amounts giving rise to such refund had never been paid. This Section 2.18(g) shall not be construed to require any indemnified party to make available its Tax returns (or any other information relating to its Taxes which it deems confidential) to the indemnifying party or any other Person.

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(h)Issuing Bank. For purposes of Section 2.18(e) and (f), the term “Lender” includes the Issuing Bank.

SECTION 2.19.Replacement or Termination of Lenders Under Certain Circumstances; Duty to Mitigate. (a) In the event (i) any Lender or the Issuing Bank delivers a certificate requesting compensation pursuant to Section 2.12, (ii) any Lender or the Issuing Bank delivers a notice described in Section 2.13, (iii) either Borrower is required to pay any additional amount or to make any indemnification payment to any Lender or the Issuing Bank or any Governmental Authority on account of any Lender or the Issuing Bank pursuant to Section 2.18 or (iv) any Lender refuses to consent to any amendment, waiver or other modification of any Loan Document requested by either Borrower that requires the consent of a greater percentage of the Lenders than the Required Lenders and such amendment, waiver or other modification is consented to by the Required Lenders, the Borrowers may, at their sole expense and effort (including with respect to the processing and recordation fee referred to in Section 10.04(b)), upon notice to such Lender or the Issuing Bank and the Administrative Agent, either (A) except in the case of clause (iv) above, so long as the Applicable Rating of either Rating Agency shall not be below BBB- or Baa3, as applicable, terminate the Commitment of such Lender and repay on the termination date specified in the applicable notice all obligations of the Borrowers owing to such Lender under this Agreement and the other Loan Documents as of such date (including, without limitation, any amounts under Section 2.12, 2.14 or 2.18) or (B) require such Lender or the Issuing Bank to transfer and assign, without recourse (in accordance with and subject to the restrictions contained in Section 10.04), all of its interests, rights and obligations under this Agreement to an assignee that shall assume such assigned obligations (which assignee may be another Lender, if a Lender accepts such assignment); provided that (x) such termination or such transfer and assignment (as the case may be) shall not conflict with any law, rule or regulation or order of any court or other Governmental Authority having jurisdiction, (y) with respect to any such transfer and assignment pursuant to clause (B) above, except in connection with an assignment to another Lender or an Affiliate thereof, the Borrowers shall have received the prior written consent of the Administrative Agent and the Issuing Bank, which consent shall not unreasonably be withheld, and (z) the Borrowers or such assignee shall have paid to the affected Lender or the Issuing Bank in immediately available funds an amount equal to the sum of the principal of and interest accrued to the date of such payment on the outstanding Loans or L/C Disbursements of such Lender or the Issuing Bank, respectively, plus all Fees and other amounts accrued for the account of such Lender or the Issuing Bank hereunder (including any amounts under Section 2.12 and Section 2.14); providedfurther that, if prior to any such termination or any such transfer and assignment (as the case may be) the circumstances or event that resulted in such Lender’s or the Issuing Bank’s claim for compensation under Section 2.12 or notice under Section 2.13 or the amounts paid pursuant to Section 2.18, as the case may be, cease to cause such Lender or the Issuing Bank to suffer increased costs or reductions in amounts received or receivable or reduction in return on capital, or cease to have the consequences specified in Section 2.13, or cease to result in amounts being payable under Section 2.18, as the case may be (including as a result of any action taken by such Lender or the Issuing Bank pursuant to paragraph (b) below), or if such Lender or the Issuing Bank shall waive its right to claim further compensation under Section 2.12 in respect of such circumstances or event or shall withdraw its notice under Section 2.13 or shall waive its right to further payments under Section 2.18 in respect of such circumstances or event or shall consent to the proposed waiver, amendment or other modification, as the case may be, then (1) the Borrowers shall not have the right to

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terminate the Commitment of such Lender pursuant to clause (A) above and (2) such Lender or the Issuing Bank shall not thereafter be required to make any such transfer and assignment hereunder, as applicable.

(b)If (i) any Lender or the Issuing Bank shall request compensation under Section 2.12, (ii) any Lender or the Issuing Bank delivers a notice described in Section 2.13 or (iii) either Borrower is required to pay any additional amount to any Lender or the Issuing Bank or any Governmental Authority on account of any Lender or the Issuing Bank pursuant to Section 2.18, then such Lender or the Issuing Bank shall use reasonable efforts (which shall not require such Lender or the Issuing Bank to incur an unreimbursed loss or unreimbursed cost or expense or otherwise take any action inconsistent with its internal policies or legal or regulatory restrictions or suffer any disadvantage or burden deemed by it to be significant) (x) to file any certificate or document reasonably requested in writing by the Borrowers or (y) to assign its rights and delegate and transfer its obligations hereunder to another of its offices, branches or affiliates, if such filing or assignment would reduce its claims for compensation under Section 2.12 or enable it to withdraw its notice pursuant to Section 2.13 or would reduce amounts payable pursuant to Section 2.18, as the case may be, in the future. The Borrowers hereby agree, jointly and severally, to pay all reasonable costs and expenses incurred by any Lender or the Issuing Bank in connection with any such filing or assignment, delegation and transfer.

SECTION 2.20.Letters of Credit. (a) General. Each of the Borrowers may request the issuance of a Letter of Credit, in a form reasonably acceptable to the Administrative Agent and the Issuing Bank, appropriately completed, for the account of such Borrower, at any time and from time to time while the Commitments remain in effect and, in the case of the Trustee only, the Trust Termination Date has not occurred. This Section 2.20 shall not be construed to impose an obligation upon the Issuing Bank to issue any Letter of Credit that is inconsistent with the terms and conditions of this Agreement.

(b)Notice of Issuance, Amendment, Renewal, Extension; Certain Conditions. In order to request the issuance of a Letter of Credit (or to amend, renew or extend an existing Letter of Credit), the requesting Borrower shall hand deliver or telecopy to the Issuing Bank and the Administrative Agent (reasonably in advance of the requested date of issuance, amendment, renewal or extension) a notice requesting the issuance of a Letter of Credit, or identifying the Letter of Credit to be amended, renewed or extended, the date of issuance, amendment, renewal or extension, the date on which such Letter of Credit is to expire (which shall comply with paragraph (c) below), the amount of such Letter of Credit, the name and address of the beneficiary thereof and such other information as shall be necessary to prepare such Letter of Credit. A Letter of Credit shall be issued, amended, renewed or extended for the account of a Borrower only if, and upon issuance, amendment, renewal or extension of each Letter of Credit for the account of such Borrower, such Borrower shall be deemed to represent and warrant that, after giving effect to such issuance, amendment, renewal or extension, the Aggregate Credit Exposure shall not exceed the Total Commitment.

(c)Expiration Date. Each Letter of Credit shall expire at the close of business on the earlier of the date one year after the date of the issuance of such Letter of Credit and the date that is five Business Days prior to the Maturity Date, unless such Letter of Credit

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expires by its terms on an earlier date. Each Letter of Credit may, upon the request of the applicable Borrower, include a provision whereby such Letter of Credit shall be renewed automatically for additional consecutive periods of 12 months or less (but not beyond the date that is five Business Days prior to the Maturity Date) unless the Issuing Bank notifies the beneficiary thereof at least 30 days prior to the then-applicable expiry date that such Letter of Credit will not be renewed.

(d)Participation. By the issuance of a Letter of Credit and without any further action on the part of the Issuing Bank or the Lenders, the Issuing Bank hereby grants to each Lender, and each such Lender hereby acquires from the applicable Issuing Bank, a participation in such Letter of Credit equal to such Lender’s Applicable Percentage of the aggregate amount available to be drawn under such Letter of Credit, effective upon the issuance of such Letter of Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of the Issuing Bank, such Lender’s Applicable Percentage of each L/C Disbursement made by the Issuing Bank and not reimbursed by the Trustee or El Paso, as the case may be, forthwith on the date due as provided in Section 2.02(f). Each Lender acknowledges and agrees that its obligation to acquire participations pursuant to this paragraph in respect of Letters of Credit is absolute and unconditional and shall not be affected by any circumstance whatsoever, including the occurrence and continuance of a Default or an Event of Default, and that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever.

(e)Reimbursement. If the Issuing Bank shall make any L/C Disbursement in respect of a Letter of Credit, the Trustee or El Paso, as the case may be, shall pay to the Administrative Agent an amount equal to such L/C Disbursement not later than 4:00 p.m., New York City time on the Business Day on which the Trustee or El Paso, as the case may be, shall have received notice from the Issuing Bank that payment of such draft will be made, or, if the Trustee or El Paso, as the case may be, shall have received such notice later than 10:00 a.m., New York City time, on any Business Day, not later than 1:00 p.m., New York City time, on the immediately following Business Day. Any failure by the Trustee or El Paso, as the case may be, to make a payment under this Section 2.20(e) shall not constitute a Default or an Event of Default if the Issuing Bank shall have been reimbursed for such L/C Disbursement out of the proceeds of a deemed Borrowing pursuant to Section 2.02(f).

(f)Obligations Absolute. The obligations of the Trustee or El Paso, as the case may be, to reimburse L/C Disbursements as provided in paragraph (e) above shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement, under any and all circumstances whatsoever, and irrespective of:

(i)any lack of validity or enforceability of any Letter of Credit or any other Loan Document, or any term or provision therein;

(ii)any amendment or waiver of or any consent to departure from all or any of the provisions of any Letter of Credit or any other Loan Document;

(iii)the existence of any claim, setoff, defense or other right that the Trustee, El Paso or any other party guaranteeing, or otherwise obligated with, the Trustee or

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El Paso, as the case may be, any Subsidiary or other Affiliate thereof or any other person may at any time have against the beneficiary under any Letter of Credit, the Issuing Bank, the Administrative Agent or any Lender or any other person, whether in connection with this Agreement, any other Loan Document or any other related or unrelated agreement or transaction;

(iv)any draft or other document presented under a Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(v)payment by the Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such Letter of Credit; and

(vi)any other act or omission to act or delay of any kind of the Issuing Bank, the Lenders, the Administrative Agent or any other person or any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section 2.20, constitute a legal or equitable discharge of the obligations of the Trustee or El Paso, as the case may be, hereunder.

Without limiting the generality of the foregoing, it is expressly understood and agreed that the absolute and unconditional obligation of the Trustee or El Paso, as the case may be, hereunder to reimburse L/C Disbursements will not be excused by the gross negligence or willful misconduct of the Issuing Bank. However, the foregoing shall not be construed to excuse the Issuing Bank from liability to the Trustee or El Paso, as the case may be, to the extent of any direct damages (as opposed to consequential damages, claims in respect of which are hereby waived by the Trustee or El Paso, as the case may be, to the extent permitted by applicable law) suffered by the Trustee or El Paso, as the case may be, that are caused by the Issuing Bank’s gross negligence or willful misconduct in determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof; it is understood that the Issuing Bank may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary and, in making any payment under any Letter of Credit (i) the Issuing Bank’s exclusive reliance on the documents presented to it under such Letter of Credit as to any and all matters set forth therein, including reliance on the amount of any draft presented under such Letter of Credit, whether or not the amount due to the beneficiary thereunder equals the amount of such draft and whether or not any document presented pursuant to such Letter of Credit proves to be insufficient in any respect, if such document on its face appears to be in order, and whether or not any other statement or any other document presented pursuant to such Letter of Credit proves to be forged or invalid or any statement therein proves to be inaccurate or untrue in any respect whatsoever and (ii) any noncompliance in any immaterial respect of the documents presented under such Letter of Credit with the terms thereof shall, in each case, be deemed not to constitute willful misconduct or gross negligence of the Issuing Bank.

(g)Disbursement Procedures. The Issuing Bank shall, promptly following its receipt thereof, examine all documents purporting to represent a demand for payment under a Letter of Credit. The Issuing Bank shall as promptly as possible give telephonic notification,

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confirmed by telecopy, to the Administrative Agent and the Trustee or El Paso, as the case may be, of such demand for payment and whether the Issuing Bank has made or will make an L/C Disbursement thereunder; provided that any failure to give or delay in giving such notice shall not relieve the Trustee or El Paso, as the case may be, of its obligation to reimburse the Issuing Bank and the Lenders with respect to any such L/C Disbursement. The Administrative Agent shall promptly give each Lender notice thereof.

(h)Interim Interest. If the Issuing Bank shall make any L/C Disbursement in respect of a Letter of Credit, then, unless the Trustee or El Paso, as the case may be, shall reimburse such L/C Disbursement in full on such date, the unpaid amount thereof shall bear interest for the account of the Issuing Bank, for each day from and including the date of such L/C Disbursement, to but excluding the earlier of the date of payment by the Trustee or El Paso, as the case may be, or the date on which the Issuing Bank is reimbursed by the Lenders pursuant to Section 2.02(f), at the rate per annum that would apply to such amount if such amount were an ABR Loan.

(i)Resignation or Removal of the Issuing Bank. The Issuing Bank may resign at any time by giving 180 days’ prior written notice to the Administrative Agent, the Lenders and the Borrowers, and may be removed at any time by the Borrowers by notice to the Issuing Bank, the Administrative Agent and the Lenders. Subject to the next succeeding paragraph, upon the acceptance of any appointment as the Issuing Bank hereunder by a Lender that shall agree to serve as successor Issuing Bank, such successor shall succeed to and become vested with all the interests, rights and obligations of the retiring Issuing Bank and the retiring Issuing Bank shall be discharged from its obligations to issue additional Letters of Credit hereunder. At the time such removal or resignation shall become effective, the Borrowers shall pay all accrued and unpaid fees pursuant to Section 2.05(c)(ii). The acceptance of any appointment as the Issuing Bank hereunder by a successor Lender shall be evidenced by an agreement entered into by such successor, in a form satisfactory to the Borrowers and the Administrative Agent, and, from and after the effective date of such agreement, (i) such successor Lender shall have all the rights and obligations of the previous Issuing Bank under this Agreement and the other Loan Documents and (ii) references herein and in the other Loan Documents to the term “Issuing Bank” shall be deemed to refer to such successor or to any previous Issuing Bank, or to such successor and all previous Issuing Banks, as the context shall require. After the resignation or removal of the Issuing Bank hereunder, the retiring Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement and the other Loan Documents with respect to Letters of Credit issued by it prior to such resignation or removal, but shall not be required to issue additional Letters of Credit.

(j)Cash Collateralization. If any Event of Default shall occur and be continuing or, with respect to the Trustee L/C Exposure only, the Trust Termination Date shall occur, the Trustee or El Paso, as the case may be, shall, on the Business Day it receives notice from the Administrative Agent or the Required Lenders thereof and of the amount to be deposited, deposit in an account with the Administrative Agent, for the benefit of the Lenders, an amount in cash equal to the Trustee L/C Exposure or the El Paso L/C Exposure, as the case may be, as of such date. Such deposit shall be held by the Administrative Agent as collateral for the payment and performance of the Obligations. The Administrative Agent shall have exclusive

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dominion and control, including the exclusive right of withdrawal, over such account. Other than any interest earned on the investment of such deposits in Permitted Investments, which investments shall be made at the option and sole discretion of the Administrative Agent, such deposits shall not bear interest. Interest or profits, if any, on such investments shall accumulate in such account. Moneys in such account shall (i) automatically be transferred to the Administrative Agent and be applied by the Administrative Agent to reimburse the Issuing Bank for L/C Disbursements for which it has not been reimbursed, (ii) be held for the satisfaction of the reimbursement obligations of the Trustee or El Paso, as the case may be, for the Trustee L/C Exposure or the El Paso L/C Exposure, as the case may be, at such time and (iii) if the maturity of the Loans has been accelerated, be transferred to the Administrative Agent and be applied to satisfy the Obligations (of both the Trustee and El Paso). If the Trustee or El Paso, as the case may be, is required to provide an amount of cash collateral hereunder as a result of the occurrence of an Event of Default, (x) such amount (to the extent not applied as aforesaid) shall be returned to the Trustee or El Paso, as the case may be, within three Business Days after all Events of Default have been cured or waived and (y) at any time that the amount of such cash collateral exceeds the Trustee L/C Exposure or El Paso L/C Exposure, as the case may be, the amount of such excess shall be promptly returned to the Trustee or El Paso, as the case may be.

SECTION 2.21.Increase of Commitments. (a) El Paso may, by written notice to the Administrative Agent, request that the Total Commitment be increased by an aggregate amount not to exceed the Incremental Facility Amount at such time. Upon the receipt of such request by the Administrative Agent, the Administrative Agent shall deliver a copy thereof to each Lender. Such notice shall set forth the amount of the requested increase (which shall be in minimum increments of $1,000,000 and a minimum amount of $10,000,000 or equal to the remaining Incremental Facility Amount) and the date on which such increase is requested to become effective (which shall be not less than 10 days nor more than 60 days after the date of such notice and which, in any event, must be on or prior to the Maturity Date), and shall offer each Lender the opportunity to increase its Commitment by its Applicable Percentage of the proposed increased amount. Each Lender shall, by notice to El Paso and the Administrative Agent given not more than 10 days after the date of the Administrative Agent’s notice, either agree to increase its Commitment by all or a portion of the offered amount (each Lender so agreeing being an “Increasing Lender”) or decline to increase its Commitment (and any Lender that does not deliver such a notice within such period of 10 days shall be deemed to have declined to increase its Commitment). In the event that, on the 10th day after the Administrative Agent shall have delivered a notice pursuant to the second sentence of this paragraph, the Increasing Lenders shall have agreed pursuant to the preceding sentence to increase their Commitments by an aggregate amount less than the increase requested by El Paso, El Paso may arrange for one or more banks or other entities (any such bank or other entity being called an “Augmenting Lender”), which may include any Lender, to extend Commitments or increase their existing Commitments in an aggregate amount equal to the unsubscribed amount; provided, however, that each Augmenting Lender (that is not an existing Lender) shall be subject to the prior written approval of the Administrative Agent and the Issuing Bank (which approvals shall not be unreasonably withheld or delayed), and the Borrowers and each Augmenting Lender shall execute all such documentation as the Administrative Agent shall reasonably specify to evidence such Augmenting Lender’s Commitment and/or its status as a Lender hereunder. Any such increase may be made in an amount that is less than the increase requested by El Paso if El Paso is unable to arrange for, or chooses not to arrange for, Augmenting Lenders.

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(b)Each of the parties hereto hereby agrees that the Administrative Agent may take any and all actions as may be reasonably necessary to ensure that, after giving effect to any increase pursuant to this Section 2.21, the outstanding Loans (if any) are held by the Lenders in accordance with their new Applicable Percentages. This may be accomplished at the discretion of the Administrative Agent, following consultation with El Paso, (i) by requiring the outstanding Loans to be prepaid with the proceeds of a new Borrowing, (ii) by permitting the Borrowings outstanding at the time of any increase in the Total Commitment pursuant to this Section 2.21 to remain outstanding until the last day of the respective Interest Periods therefor, even though the Lenders would hold the Loans comprising such borrowings other than in accordance with their new Applicable Percentage, (iii) by requiring each Increasing Lender and Augmenting Lender to purchase by assignment from the other Lenders (in which case such other Lenders shall assign to the Increasing Lenders and Augmenting Lenders) such portion of the outstanding Loans, if any, owing to them as shall be designated by the Administrative Agent such that, after giving effect to all such purchases and assignments, the outstanding Loans owing to each Lender shall equal such Lender’s Applicable Percentage of the aggregate amount of Loans owing to all Lenders or (iv) by any combination of the foregoing. Any prepayment described in this paragraph (b) shall be subject to Section 2.14, but shall otherwise be without premium or penalty. In addition, on the effective date of any such increase in the Total Commitment pursuant to this Section 2.21, each Increasing Lender and Augmenting Lender shall be deemed to have purchased by assignment from the other Lenders (and such other Lenders shall be deemed to have assigned to the Increasing Lenders and Augmenting Lenders) a portion of the participations (if any) then held by such other Lenders in the outstanding L/C Exposure, such that, after giving effect to all such deemed purchases and assignments, each Lender’s L/C Exposure shall equal such Lender’s Applicable Percentage of the aggregate L/C Exposure at such time.

(c)Notwithstanding the foregoing, no increase in the Total Commitment shall become effective under this Section 2.21 unless (i) on the date of such increase, the conditions set forth in paragraphs (b) and (c) of Section 4.01 shall be satisfied and the Administrative Agent shall have received a certificate to that effect dated such date and executed by a Financial Officer of El Paso, (ii) the Borrowers shall have received all consents, approvals and authorizations of, and shall have made all registrations and filings with, any Governmental Authority required in connection with such increase, each of which shall be in full force and effect and not subject to any appeal or stay, (iii) if requested, the Administrative Agent shall have received legal opinions, certificates and board resolutions consistent with those delivered on the Effective Date under paragraphs (a), (b) and (c) of Section 4.02, and (iv) the Borrowers shall have delivered to the Administrative Agent such other consents, authorizations, certificates and other documents as the Administrative Agent may reasonably request in connection with such increase (including, without limitation, any new or replacement Notes requested by the applicable Increasing Lenders or Augmenting Lenders pursuant to Section 2.04(e)).

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ARTICLE IIIRepresentations and Warranties

Each of El Paso and, subject to Section 10.19, the Trustee represents and warrants to the Administrative Agent, the Issuing Bank and each of the Lenders that as of the Effective Date and thereafter on each date as required by Section 4.01(b):

SECTION 3.01.Organization; Powers. (a) El Paso and each of the Material Subsidiaries (i) is duly organized, validly existing and in good standing under the laws of the state of its organization, (ii) has all requisite power and authority to own its property and assets and to carry on its business as now conducted and as proposed to be conducted, (iii) is qualified to do business in, and is in good standing in, every jurisdiction where such qualification is required, except where the failure so to qualify would not reasonably be expected to result in a Material Adverse Effect, and (iv) has the corporate power and authority to execute, deliver and perform its obligations under each of the Loan Documents to which it is or will be a party and each other agreement or instrument contemplated hereby to which it is or will be a party and to borrow hereunder.

(b)BONY is a national banking association duly incorporated, validly existing and in good standing under the laws of the United States of America, and in its capacity as Trustee, (i) has all requisite power and authority to own its property and assets and to carry on its business as now conducted and as proposed to be conducted and (ii) has all requisite power and authority to execute, deliver and perform its obligations under each of the Loan Documents and each other agreement or instrument contemplated hereby to which it is or will be a party and to borrow hereunder.

SECTION 3.02.Authorization. (a) The execution, delivery and performance by it and each of its Material Subsidiaries (as applicable) of each of the Loan Documents, the Trust Agreement and the Purchase Contract to which it is or will be a party and (b) the Borrowings by it hereunder, the request for the issuance of Letters of Credit and the use by it of the proceeds of the Loans and the Letters of Credit (collectively, the “Transactions”), (x) have been duly authorized by all requisite corporate, trust and, if required, stockholder action and (y) will not (i) violate (A) any provision of law, statute, rule or regulation, or of the articles of incorporation or other constitutive documents or by-laws of El Paso or any of its Material Subsidiaries or of the Trust Agreement, as applicable, (B) any order of any Governmental Authority or (C) any provision of any indenture, agreement or other instrument to which it is a party or by which it or any of its property is or may be bound, (ii) be in conflict with, result in a breach of or constitute (alone or with notice or lapse of time or both) a default under, or give rise to any right to accelerate or to require the prepayment, repurchase or redemption of any obligation under any such indenture, agreement or other instrument or (iii) result in the creation or imposition of any Lien upon or with respect to any property or assets now owned or hereafter acquired by it.

SECTION 3.03.Enforceability. Each of the Loan Documents has been duly executed and delivered by it and constitutes its legal, valid and binding obligation enforceable against it in accordance with such document’s terms, except as enforceability may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the

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enforcement of creditors’ rights generally and by general equitable principles (whether enforcement is sought by proceedings in equity or at law).

SECTION 3.04.Governmental Approvals. Except as set forth on Schedule 3.04, no action, consent or approval of, registration or filing with or any other action by, any Governmental Authority is or will be required in connection with the Transactions, except for such as have been made or obtained, are in full force and effect and are not subject to any appeal or stay.

SECTION 3.05.Financial Statements. El Paso has heretofore furnished to the Lenders its consolidated balance sheets and related statements of operations, shareholders’ equity and cash flows (a) as of and for the fiscal year ended December 31, 2010, audited by and accompanied by the opinion of KPMG LLP, independent public accountants, and (b) as of and for the fiscal quarter and the portion of the fiscal year ended September 30, 2011, certified by a Financial Officer. Such financial statements present fairly the financial condition and results of operations and cash flows of El Paso and its consolidated Subsidiaries as of such dates and for such periods. Such balance sheets and the notes thereto disclose all material liabilities, direct or contingent, of El Paso and its consolidated Subsidiaries as of the dates thereof. Such financial statements were prepared in accordance with GAAP applied on a consistent basis (except as approved by such accountants or officer, as the case may be, and disclosed therein).

SECTION 3.06.No Material Adverse Change. There has been no material adverse change in the business, assets, operations or financial condition of El Paso and the Subsidiaries, taken as a whole, since December 31, 2010.

SECTION 3.07.Subsidiaries. As of the Effective Date, El Paso has no Material Subsidiaries and, except as set forth on Schedule 3.07, no other Subsidiaries.

SECTION 3.08.Litigation; Compliance with Laws. (a) Except as set forth on Schedule 3.08, there are no actions, suits or proceedings at law or in equity or by or before any Governmental Authority now pending or, to its knowledge, threatened against or affecting it or, in the case of El Paso, the Subsidiaries or any business, property or rights of any such person (i) that in any manner draws into question the validity or enforceability of this Agreement or any other Loan Document or (ii) that would reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

(b)Except as set forth on Schedule 3.08, neither it nor, in the case of El Paso, any of the Subsidiaries or any of their respective material properties or assets, is in violation of, nor will the continued operation of their material properties and assets as currently conducted violate, any law, rule or regulation, or is in default with respect to any judgment, writ, injunction, decree or order of any Governmental Authority, where such violation or default would reasonably be expected to result in a Material Adverse Effect.

SECTION 3.09.Federal Reserve Regulations. (a) Neither it nor, in the case of El Paso, any of the Subsidiaries, is engaged principally, or as one of its important activities, in the business of extending credit for the purpose of buying or carrying Margin Stock.

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(b)No part of the proceeds of any Loan made to it or any Letter of Credit issued for its benefit will be used, whether directly or indirectly, and whether immediately, incidentally or ultimately, for any purpose that entails a violation of, or that is inconsistent with, the provisions of the Regulations of the Board, including Regulation T, Regulation U or Regulation X.

SECTION 3.10.Investment Company Act. It is not an “investment company as defined in, or subject to regulation under, the Investment Company Act of 1940, as amended.

SECTION 3.11.Use of Proceeds. It will use the proceeds of the Loans and will request the issuance of Letters of Credit only for the purposes specified in Section 5.08.

SECTION 3.12.Tax Returns. Each of El Paso and the Subsidiaries has filed or caused to be filed all Federal, state, local and foreign tax returns or materials required to have been filed by it and has paid or caused to be paid all taxes due and payable by it and all assessments received by it, except taxes that are being contested in good faith by appropriate proceedings and for which El Paso or such Subsidiary, as applicable, shall have set aside on its books adequate reserves.

SECTION 3.13.No Material Misstatements. (i) The Annual Report on Form 10-K filed by El Paso with the SEC for the fiscal year ended December 31, 2010, (ii) the Quarterly Report on Form 10-Q filed by El Paso with the SEC for the fiscal quarter ended September 30, 2011 and (iii) any Current Reports on Form 8-K filed by El Paso with the SEC prior to the Effective Date, taken as a whole, do not contain any material misstatement of fact or omit to state any material fact necessary to make the statements therein, in light of the circumstances under which they are made, not materially misleading; provided that to the extent any part of such information was based upon or constitutes a forecast or projection, El Paso represents only that it acted in good faith and utilized reasonable assumptions and due care in the preparation of such information.

SECTION 3.14.Employee Benefit Plans. El Paso and its ERISA Affiliates are in compliance in all material respects with the applicable provisions of ERISA and the Code and the regulations and published interpretations thereunder. No ERISA Event has occurred or is reasonably expected to occur that, when taken together with all other such ERISA Events, would reasonably be expected to result in a Material Adverse Effect. Schedule SB to the most recent annual report filed with the United States Internal Revenue Service with respect to each Plan is complete and accurate in all material respects. Since the date of the Schedule SB in effect on the Effective Date, there has been no material adverse change in the funded status of any Plan. None of El Paso or any of its ERISA Affiliates has incurred any liability as a result of a Plan termination which remains outstanding which would subject El Paso or any of its ERISA Affiliates to a liability in excess of $7,500,000.

SECTION 3.15.Environmental Matters. Except as set forth in Schedule 3.15:

(a)The properties owned or operated by El Paso and the Subsidiaries (the “Properties”) do not contain any Hazardous Materials in amounts or concentrations which (i) constitute or constituted a violation of, or (ii) could reasonably be expected to give rise to

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liability under, Environmental Laws, which violations and liabilities, in the aggregate, would reasonably be expected to result in a Material Adverse Effect;

(b)All Environmental Permits have been obtained and are in effect with respect to the Properties and operations of El Paso and the Subsidiaries, and the Properties and all operations of El Paso and the Subsidiaries are in compliance with all Environmental Laws and all necessary Environmental Permits, except to the extent that such non-compliance or failure to obtain any necessary permits, in the aggregate, would not reasonably be expected to result in a Material Adverse Effect;

(c)There have been no Releases or threatened Releases at, from, under or proximate to the Properties or otherwise in connection with the operations of El Paso or the Subsidiaries, which Releases or threatened Releases, in the aggregate, would reasonably be expected to result in a Material Adverse Effect;

(d)None of El Paso and the Subsidiaries has received any notice of an Environmental Claim or request for information under any Environmental Law in connection with the Properties or the operations of El Paso or the Subsidiaries or with regard to any person whose liabilities for environmental matters El Paso or any Subsidiary has retained or assumed, in whole or in part, contractually, by operation of law or otherwise, which, in the aggregate, would reasonably be expected to result in a Material Adverse Effect, nor do El Paso or the Subsidiaries have reason to believe that any such notice will be received or is being threatened; and

(e)Hazardous Materials have not been transported from the Properties, nor have Hazardous Materials been generated, treated, stored or disposed of at, on or under any of the Properties in a manner that could reasonably be expected to give rise to liability under any Environmental Law, which in either case would reasonably be expected to result in a Material Adverse Effect, nor have El Paso or the Subsidiaries retained or assumed any liability, contractually, by operation of law or otherwise, with respect to the generation, treatment, storage or disposal of Hazardous Materials, which transportation, generation, treatment, storage or disposal, or retained or assumed liabilities, in the aggregate, would reasonably be expected to result in a Material Adverse Effect.

SECTION 3.16.Insurance. El Paso and the Subsidiaries have insurance in such amounts and covering such risks and liabilities as are in accordance with normal industry practice. All such insurance is in full force and effect and all premiums have been duly paid.

SECTION 3.17.Anti-Terrorism Laws, etc. (a) Such Borrower’s use of the proceeds of the Loans will not violate the Trading with the Enemy Act, as amended, or any of the foreign assets control regulations of the United States Treasury Department (31 CFR, Subtitle B, Chapter V, as amended) or any enabling legislation or executive order relating thereto.

(b)Neither such Borrower nor any Subsidiary thereof (i) is a Person described or designated in the Specially Designated Nationals and Blocked Persons List of the Office of Foreign Assets Control or in Section 1 of the Anti-Terrorism Order or (ii) to such Borrower’s knowledge, engages in any dealings or transactions with any such person. Each Borrower and the Subsidiaries are in compliance, in all material respects, with the USA Patriot Act.

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ARTICLE IVConditions of Lending

The obligations of the Lenders to make Loans and of the Issuing Bank to issue Letters of Credit hereunder are subject to the satisfaction of the following conditions:

SECTION 4.01.All Credit Events. On the date of each Borrowing and on the date of each issuance, amendment, renewal or extension of a Letter of Credit (each such event being called a “Credit Event”):

(a)The Administrative Agent shall have received a notice of such Borrowing as required by Section 2.03 (or such notice shall have been deemed given in accordance with Section 2.03) or, in the case of the issuance, amendment, renewal or extension of a Letter of Credit, the Issuing Bank and the Administrative Agent shall have received a notice requesting the issuance, amendment, renewal or extension of such Letter of Credit as required by Section 2.20(b).

(b)Except in the case of a Borrowing that does not increase the aggregate principal amount of Loans outstanding of any Lender, the representations and warranties set forth herein (other than, with respect to any Credit Event after the Effective Date, the representations and warranties set forth in Sections 3.06 and 3.08(a)) and in the other Loan Documents shall be true and correct in all material respects on and as of the date of such Credit Event with the same effect as though made on and as of such date, except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties shall have been true and correct in all material respects as of such earlier date).

(c)At the time of and immediately after such Credit Event, no Event of Default or Default shall have occurred and be continuing.

Each Credit Event shall be deemed to constitute a representation and warranty by each Borrower on the date of such Credit Event as to the matters specified in paragraphs (b) (except as aforesaid) and (c) of this Section 4.01.

SECTION 4.02.Effective Date. On the Effective Date (it being acknowledged and agreed by the parties hereto that this Agreement shall not become effective until the date on which the following conditions have been satisfied):

(a)The Administrative Agent shall have received, on behalf of itself, the Lenders, the Syndication Agent and the Issuing Bank, favorable written opinions of (i) Davis Polk & Wardwell LLP, counsel for El Paso, (ii) Andrews Kurth LLP, counsel for the Trustee, (iii) each local regulatory counsel listed on Schedule 4.02(a), and (iv) the General Counsel of El Paso, in each case (A) dated the Effective Date, (B) addressed to the Issuing Bank, the Administrative Agent, the Syndication Agent and the Lenders, (C) covering such customary matters relating to the Loan Documents and the Transactions as the Administrative Agent shall reasonably request and (D) otherwise in form and substance reasonably satisfactory to the Administrative Agent, and the Borrowers hereby request such counsel to deliver such opinions.

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(b)The Administrative Agent shall have received (i) a certificate of the Secretary or Assistant Secretary of El Paso dated the Effective Date and certifying (A) that attached thereto is a true and complete copy of the certificate or articles of incorporation of El Paso filed with the Secretary of State of Texas on or prior to the Effective Date and as in effect on the Effective Date, (B) that attached thereto is a true and complete copy of the by-laws of El Paso as in effect on the Effective Date and at all times since a date prior to the date of the resolutions described in clause (C) below, (C) that attached thereto is a true and complete copy of resolutions duly adopted by the Board of Directors of El Paso authorizing the execution, delivery and performance of the Loan Documents to which El Paso is or is to be a party and the borrowings hereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect, (D) that attached thereto is a true and complete copy of the Trust Agreement, together with any supplemental instructions pursuant thereto required in connection with this Agreement, and that the Trust Agreement has not been modified, rescinded or amended and is in full force and effect, (E) that attached thereto are true and complete copies of all governmental approvals listed on Schedule 3.04, each of which is in full force and effect as of the Effective Date, and (F) as to the incumbency and specimen signature of each officer executing this Agreement or any other document delivered in connection herewith on behalf of El Paso; (ii) a certificate of another officer of El Paso as to the incumbency and specimen signature of the Secretary or Assistant Secretary executing the certificate pursuant to clause (i) above; (iii) a certificate of the Secretary or Assistant Secretary of BONY dated the Effective Date and certifying as to the incumbency and specimen signature of each Person executing this Agreement or any other document delivered in connection herewith on behalf of the Trustee; and (iv) such other customary closing documents as the Lenders, the Issuing Bank, the Syndication Agent or the Administrative Agent may reasonably request.

(c)The Administrative Agent shall have received good standing certificates with respect to each Borrower (with respect to El Paso, from the Secretary of State of Texas and the Secretary of State of New Mexico, and with respect to BONY, from the Comptroller of the Currency), in each case issued as of a recent date.

(d)The Administrative Agent shall have received a certificate, dated the Effective Date and signed by a Financial Officer of El Paso, certifying that (i) the representations and warranties set forth in this Agreement and in the other Loan Documents that pertain to El Paso are true and correct in all material respects on and as of the Effective Date with the same effect as though made on and as of such date, except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties were true and correct in all material respects as of such earlier date), and (ii) no Event of Default or Default that pertains to El Paso has occurred and is continuing.

(e)The Administrative Agent shall have received a certificate, dated the Effective Date and signed by a Senior Associate of the Trustee, certifying that (i) the representations and warranties set forth in this Agreement and in the other Loan Documents that pertain to the Trustee are true and correct in all material respects on and as of the Effective Date with the same effect as though made on and as of such date, except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties were true and correct in all material respects as of such earlier

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date), and (ii) no Event of Default or Default that pertains to the Trustee has occurred and is continuing.

(f)(i)  The Administrative Agent shall have received all Fees and other amounts due and payable on or prior to the Effective Date, including, to the extent invoiced, reimbursement or payment of all out-of-pocket fees and expenses required to be reimbursed or paid by the Borrowers hereunder or under any other Loan Document or under the Commitment Letter dated November 3, 2011, between the Administrative Agent and El Paso; and (ii) the Syndication Agent shall have received all fees payable by El Paso pursuant to that certain fee letter agreement, dated the Effective Date, between the Syndication Agent and El Paso, together with, to the extent invoiced, reimbursement or payment of all reasonable fees and out-of-pocket disbursements of counsel to the Syndication Agent and other out-of-pocket expenses of the Syndication Agent required to be reimbursed or paid by the Borrowers hereunder or under any other Loan Document.

(g)All requisite Governmental Authorities shall have approved or consented to the Transactions to the extent required (and such approvals shall be in full force and effect) and there shall be no action, actual or threatened, before any Governmental Authority or arbitrator that (a) has a reasonable likelihood of restraining, preventing or imposing burdensome conditions on the Transactions or (b) would reasonably be expected to result in a Material Adverse Effect.

(h)The Lenders shall have received, to the extent requested, all documentation and other information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including the USA Patriot Act.

ARTICLE VAffirmative Covenants

Each of El Paso and, subject to Section 10.19, the Trustee covenants and agrees with each Lender that so long as this Agreement shall remain in effect and until the Commitments have been terminated and the principal of and interest on each Loan, all Fees and all other expenses or amounts payable under any Loan Document shall have been paid in full and all Letters of Credit have been canceled or have expired and all amounts drawn thereunder have been reimbursed in full (or sufficient cash collateral has been deposited with the Administrative Agent in an amount equal to the then outstanding L/C Exposure), unless the Required Lenders shall otherwise consent in writing, each of the Borrowers will, and El Paso will cause each of the Material Subsidiaries to:

SECTION 5.01.Existence; Businesses and Properties. (a) Do or cause to be done all things necessary to preserve, renew and keep in full force and effect its legal existence.

(b)Do or cause to be done all things necessary to obtain, preserve, renew, extend and keep in full force and effect the rights, licenses, permits (including Environmental Permits), franchises and authorizations material to the conduct of its business; comply in all material respects with all applicable laws, rules, regulations and decrees and orders of any

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Governmental Authority (including, without limitation, ERISA and Environmental Laws and Environmental Permits), whether now in effect or hereafter enacted; conduct any Remedial Action in substantial compliance with Environmental Laws; and at all times maintain and preserve all property material to the conduct of such business and keep such property in good repair, working order and condition, ordinary wear and tear excepted; except in each case where the failure to do so would not reasonably be expected to result in a Material Adverse Effect.

SECTION 5.02.Insurance. With respect to El Paso, keep its insurable properties, the insurable properties of the Material Subsidiaries and the insurable properties of the Trustee adequately insured at all times by financially sound and reputable insurers; maintain such other insurance, to such extent and against such risks, including nuclear hazard, fire and other risks insured against by extended coverage, as is customary with companies in the same or similar businesses operating in the same or similar locations; and maintain such other insurance as may be required by law.

SECTION 5.03.Obligations and Taxes. Pay its Indebtedness and other obligations promptly and in accordance with their terms and pay and discharge promptly when due all material taxes, assessments and governmental charges or levies imposed upon it or upon its income or profits or in respect of its property, before the same shall become delinquent or in default, as well as all lawful claims for labor, materials and supplies or otherwise that, if unpaid, might give rise to a Lien upon such properties or any part thereof; provided, however, that such payment and discharge shall not be required with respect to any such tax, assessment, charge, levy or claim so long as the validity or amount thereof shall be contested in good faith by appropriate proceedings and the applicable Borrower shall have set aside on its books adequate reserves with respect thereto in accordance with GAAP and such contest operates to suspend collection of the contested obligation, tax, assessment or charge and enforcement of a Lien.

SECTION 5.04.Financial Statements, Reports, etc. Furnish to the Administrative Agent (and the Administrative Agent shall promptly after receipt thereof make available to each Lender):

(a)with respect to El Paso, within 120 days after the end of each fiscal year, its consolidated balance sheet and related statements of operations, stockholders’ equity and cash flows showing its financial condition as of the close of such fiscal year and the results of its operations during such year, all audited by KPMG LLP or other independent public accountants of recognized national standing and accompanied by an opinion of such accountants (which shall not be qualified in any material respect) to the effect that such consolidated financial statements fairly present its financial condition and results of operations in accordance with GAAP consistently applied;

(b)with respect to El Paso, within 60 days after the end of each of the first three fiscal quarters of each fiscal year, its consolidated balance sheet and related statements of operations, stockholders’ equity, and cash flows showing its financial condition as of the close of such fiscal quarter and the results of its operations during such fiscal quarter and the then elapsed portion of the fiscal year, all certified by one of its Financial Officers, as fairly presenting its financial condition and results of operations on a consolidated basis in accordance with GAAP consistently applied, subject to normal year-end audit adjustments;

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(c)with respect to El Paso, concurrently with any delivery of financial statements under sub-paragraph (a) or (b) above, a certificate of a Financial Officer certifying that no Event of Default or Default has occurred or, if such an Event of Default or Default has occurred, specifying the nature and extent thereof and any corrective action taken or proposed to be taken with respect thereto;

(d)with respect to El Paso, promptly after the same become publicly available, copies of all periodic and other reports and definitive proxy statements (other than any registration statement on Form S-8 or its equivalent) filed by it or any Subsidiary with the SEC, or distributed to its shareholders generally;

(e)with respect to the Trustee, concurrently with the delivery thereof to El Paso, copies of its periodic trust reports;

(f)with respect to El Paso, promptly after El Paso shall have received notice thereof, notice of any change in the debt rating of the Index Debt, or any notice that El Paso or any Index Debt shall be placed on “CreditWatch” or “WatchList” or any similar list maintained by either Rating Agency, in each case with negative implications;

(g)promptly after the request by any Lender, all documentation and other information that such Lender reasonably requests in order to comply with its ongoing obligations under applicable “know your customer” and anti-money laundering rules and regulations, including the USA Patriot Act; and

(h)promptly, from time to time, such other information regarding the operations, business affairs and financial condition of such Borrower or any Subsidiary, or compliance with the terms of any Loan Document, as the Administrative Agent or any Lender may reasonably request.

SECTION 5.05.Litigation and Other Notices. Furnish to the Administrative Agent written notice of the following promptly after any Responsible Officer of such Borrower obtains actual knowledge thereof:

(a)any Event of Default or Default, specifying the nature and extent thereof and the corrective action (if any) taken or proposed to be taken with respect thereto; and

(b)the filing or commencement of any action, suit or proceeding, whether at law or in equity or by or before any Governmental Authority, against it or, in the case of El Paso, any Material Subsidiary that would reasonably be expected to result in a Material Adverse Effect.

SECTION 5.06.Employee Benefits. With respect to El Paso, furnish to the Administrative Agent as soon as possible, and in any event within 10 days, after any Responsible Officer of El Paso or any ERISA Affiliate knows or has reason to know that any ERISA Event has occurred that, alone or together with any other ERISA Event, would reasonably be expected to result in liability of El Paso in an aggregate amount exceeding $7,500,000 or requiring payments exceeding $2,500,000 in any year, a statement of a Financial Officer of El Paso setting

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forth details as to such ERISA Event and the action, if any, that El Paso proposes to take with respect thereto.

SECTION 5.07.Maintaining Records; Access to Properties and Inspections. (a) Keep adequate records and books of account, in which full and correct entries shall be made of all of its financial transactions and its assets and business so as to permit El Paso and its Subsidiaries to present financial statements in accordance with GAAP.

(b)Permit any representatives designated by the Administrative Agent or any Lender to visit and inspect the financial records and the properties of such Borrower or such Material Subsidiary upon reasonable notice and at reasonable times and as often as reasonably requested and to make extracts from and copies of such financial records, and permit any representatives designated by the Administrative Agent or any Lender to discuss the affairs, finances and condition of such Borrower or such Material Subsidiary with the officers thereof and independent accountants therefor (subject to reasonable requirements of confidentiality, including requirements imposed by law or by contract); provided that the costs and expenses incurred by any such Lender in connection with any such visitation, inspection, extracts, copies or discussions shall be, upon the occurrence and during the continuation of a Default or an Event of Default, for the account of El Paso, and, in all other circumstances, for the account of such Lender. It is understood and agreed that the costs and expenses incurred by the Administrative Agent in connection with any such visitation, inspection, extracts, copies or discussions shall be for the account of El Paso.

SECTION 5.08.Use of Proceeds. (a) Use the proceeds of the Loans made to it on and after the Effective Date (i) in the case of El Paso, solely (A) to provide working capital to El Paso, (B) for general corporate purposes, including commercial paper back-up, and (C) to pay related fees and expenses, and (ii) in the case of the Trustee, solely (A) to finance the purchase of Nuclear Fuel by the Trustee in accordance with the Trust Agreement and the Purchase Contract, (B) to pay interest on and accrued fees with respect to the Trust Senior Unsecured Notes, (C) to pay interest and other amounts payable hereunder by the Trustee as needed and (D) to pay related fees and expenses; and (b) request the issuance of Letters of Credit (i) in the case of Letters of Credit issued for the account of El Paso, solely for general corporate purposes, and (ii) in the case of Letters of Credit issued for the account of the Trustee, solely to support obligations incurred by the Trustee in respect of the purchase of Nuclear Fuel in accordance with the Trust Agreement and the Purchase Contract.

SECTION 5.09.Subsidiary Guarantors. El Paso shall promptly (and in any event within thirty (30) days (or such longer period not to exceed forty-five (45) days as the Administrative Agent may agree in its reasonable discretion) after the creation, acquisition or existence of any Material Subsidiary) cause each Material Subsidiary to execute a guarantee of all the El Paso Obligations pursuant to a Subsidiary Guarantee Agreement. In furtherance of the foregoing, El Paso shall give prompt notice to the Administrative Agent of the creation, acquisition or existence of any such Material Subsidiary.

SECTION 5.10.Maintenance of Ratings. Use commercially reasonable efforts to cause at all times Applicable Ratings to be in effect.

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ARTICLE VINegative Covenants

Each of El Paso and, subject to Section 10.19, the Trustee covenants and agrees with each Lender that, so long as this Agreement shall remain in effect and until the Commitments have been terminated and the principal of and interest on each Loan, all Fees and all other expenses or amounts payable under any Loan Document have been paid in full and all Letters of Credit have been canceled or have expired and all amounts drawn thereunder have been reimbursed in full (or sufficient cash collateral has been deposited with the Administrative Agent in an amount equal to the then outstanding L/C Exposure), unless the Required Lenders shall otherwise consent in writing:

SECTION 6.01.Subsidiary Indebtedness. El Paso will not permit any Subsidiary that is not a Subsidiary Guarantor to incur, create, assume or permit to exist (collectively, “incur”) any Indebtedness, except:

(a)Indebtedness of any such Subsidiary owed to El Paso or any Subsidiary Guarantor;

(b)Indebtedness of any Receivables Subsidiary incurred pursuant to the Receivables Facility Documents in an aggregate principal amount not in excess of $100,000,000 outstanding at any time; and

(c)Indebtedness of Subsidiaries not otherwise permitted by the foregoing paragraphs of this Section 6.01; provided that the aggregate principal amount of all Indebtedness of all such Subsidiaries outstanding under this paragraph (c) and Indebtedness secured by Liens permitted by Section 6.02(o) shall not exceed 15% of Total Consolidated Capital.

SECTION 6.02.Liens. Neither Borrower will, nor will El Paso permit any Subsidiary to, create, incur, assume or permit to exist any Lien on any property or assets (including stock or other securities of any person, including any Subsidiary) now owned or hereafter acquired by it or on any income or revenues or rights in respect of any thereof, except:

(a)Liens on property or assets of El Paso existing on the date hereof and set forth in Schedule 6.02; provided that such Liens shall secure only those obligations which they secure on the date hereof;

(b)Liens to secure the Obligations;

(c)any Lien existing on any Operating Property prior to the acquisition thereof by El Paso or any Subsidiary to secure Indebtedness assumed by El Paso or any Subsidiary; provided that (i) such Lien is not created in contemplation of or in connection with such acquisition and (ii) such Lien does not apply to any other property or assets of either Borrower or any Subsidiary;

(d)Liens for taxes or assessments by any Governmental Authority not yet due or which are being contested in compliance with Section 5.03;

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(e)carriers’, warehousemen’s, mechanics’, materialmen’s, repairmen’s, landlords’, licensors’ or other like Liens arising in the ordinary course of business and securing obligations that are not due and payable or which are being contested in compliance with Section 5.03;

(f)pledges and deposits made in the ordinary course of El Paso’s business in compliance with workmen’s compensation, unemployment insurance and other social security laws or regulations;

(g)deposits by El Paso to secure the performance of bids, trade contracts (other than for Indebtedness), leases (other than Capital Lease Obligations), statutory obligations, surety and appeal bonds, performance bonds and other obligations of a like nature incurred in the ordinary course of business;

(h)zoning restrictions, easements, rights-of-way, restrictions on use of real property or permit or license requirements and other similar encumbrances incurred in the ordinary course of business which, in the aggregate, are not substantial in amount and do not materially detract from the value of the property subject thereto or interfere with the ordinary conduct of the businesses of the Borrowers or any Material Subsidiary;

(i)Liens to secure Indebtedness incurred by El Paso in connection with the acquisition or lease by El Paso in the ordinary course of business, after the date hereof, of furniture, fixtures, equipment and other assets not owned by El Paso on the date hereof; provided that (i) such Indebtedness shall not be secured by any Operating Property of El Paso other than the Operating Property with respect to which such Indebtedness is incurred and (ii) the Lien securing such Indebtedness shall be created within 90 days of the incurrence of such Indebtedness;

(j)Liens of a Mortgage Indenture to secure First Mortgage Bonds in an aggregate principal amount not to exceed $550,000,000 issued in exchange for or to secure or to repurchase, repay or otherwise refinance the Indebtedness of El Paso under the Senior Unsecured Notes;

(k)Liens to secure Indebtedness of any person existing at the time such person is merged into or consolidated with, or such person disposes of all or substantially all its properties (or those of a division) to, El Paso or any Material Subsidiary;

(l)Liens to secure Indebtedness incurred by El Paso to acquire, construct, develop or substantially repair, alter or improve Operating Property or to provide funds for any such purpose or for reimbursement of funds previously expended for any such purpose; provided that such Indebtedness is incurred contemporaneously with, or within 24 months after, such acquisition or the completion of construction, development or substantial repair, alteration or improvement;

(m)Liens to secure, directly or indirectly, (i) El Paso’s obligations with respect to debt issued by any Governmental Authority, including debt represented by securities issued by any such Governmental Authority (or providers of credit enhancement with respect to such securities), including, without limitation, El Paso’s obligations with respect to industrial

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development, pollution control or similar revenue bonds incurred for the purpose of financing all or any part of the purchase price or the cost of substantially repairing or altering, constructing, developing or substantially improving El Paso’s Operating Property (any such debt being referred to herein as “Specified Debt”), and (ii) El Paso’s obligations with respect to Indebtedness issued in exchange for or to repurchase or repay or otherwise refinance any Specified Debt;

(n)Liens on the property of any Receivables Subsidiary incurred pursuant to the Receivables Facility Documents and Liens in favor of any Receivables Subsidiary granted by El Paso or any other Subsidiary with respect to Receivables purportedly sold to any Receivables Subsidiary by El Paso or such other Subsidiary pursuant to a Receivables Facility;

(o)Liens created by a Mortgage Indenture and securing the payment of the fees and expenses of the trustee in respect of such Mortgage Indenture;

(p)one or more attachments or other similar Liens on assets of El Paso or any Subsidiary arising in connection with court proceedings (i) in an aggregate principal amount not in excess of $10,000,000 (so long as El Paso or such Subsidiary has set aside adequate reserves therefor) or (ii) the execution of which has been stayed or which has been appealed and secured, if necessary, by an appeal bond; provided that in each case no Event of Default shall result therefrom;

(q)any Lien arising by operation of law on the assets of El Paso or any Subsidiary in favor of any Governmental Authority with respect to any franchise, grant, license, permit or contract; and

(r)Liens that are not otherwise permitted by any of the foregoing paragraphs of this Section 6.02; provided that, at the time that any such Lien is granted (and after giving effect thereto), the aggregate outstanding principal amount of all Indebtedness outstanding under Section 6.01(c) and Indebtedness secured by Liens permitted by this Section 6.02(r) shall not exceed 15% of Total Consolidated Capital.

SECTION 6.03.Sale and Lease-Back Transactions. Neither Borrower will, nor will El Paso permit any Material Subsidiary to, enter into any arrangement, directly or indirectly, with any person whereby it shall sell or transfer any property, real or personal, used or useful in its business, whether now owned or hereafter acquired, and thereafter rent or lease such property or other property which it intends to use for substantially the same purpose or purposes as the property being sold or transferred (a “Sale Lease-Back Transaction”), except for (i) any Sale Lease-Back Transaction that constitutes a Capital Lease Obligation otherwise permitted to be incurred under this Agreement, and (ii) Sale Lease-Back Transactions of real property and tangible personal property with an aggregate fair market value not to exceed $50,000,000 at any time.

SECTION 6.04.Investments, Loans and Advances. Neither Borrower will, nor will El Paso permit any Material Subsidiary to, purchase, hold or acquire any capital stock, evidences of indebtedness or other securities of, make or permit to exist any loans or advances to, or make or permit to exist any investment or any other interest in, any other person in excess

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of $5,000,000 at any time outstanding (without giving effect to any write-offs or write-downs thereof), except:

(a)investments by El Paso or any Material Subsidiary in the capital stock of a Subsidiary; provided however, that the aggregate cumulative amount of El Paso’s and the Material Subsidiaries’ investments in, and loans and advances to, such Subsidiaries that are not Loan Parties shall not exceed $20,000,000;

(b)Permitted Investments;

(c)Investments of El Paso existing on the Effective Date and set forth on Schedule 6.04;

(d)Investments received in connection with the bankruptcy or reorganization of customers and suppliers and in settlement of delinquent obligations of, and other disputes with, customers and suppliers arising in the ordinary course of business;

(e)Investments in intercompany loans between and among El Paso and any Subsidiary Guarantor; and

(f)Investments made in connection with and to facilitate the Receivables Facilities.

SECTION 6.05.Mergers, Consolidations and Sales of Assets and Acquisitions. Neither Borrower will, nor will El Paso permit any Material Subsidiary to, merge into or consolidate with any other person, or permit any other person to merge into or consolidate with it, or sell, transfer, lease or otherwise dispose of (in one transaction or in a series of transactions) all or any substantial part of its assets (whether now owned or hereafter acquired) or any capital stock of any Material Subsidiary, or purchase, lease or otherwise acquire (in one transaction or a series of transactions) all or any substantial part of the assets of any other person except that (a) the Trustee may purchase and sell Nuclear Fuel in accordance with the provisions of the Purchase Contract, (b) El Paso and any Material Subsidiary may sell Receivables pursuant to a Receivables Facility, (c) El Paso may sell or contribute transmission assets to the extent that FERC orders such assets to be sold in connection with joining a Regional Transmission Organization, (d) El Paso or any Material Subsidiary may merge with another person if (x) El Paso or such Material Subsidiary, as the case may be, is the surviving corporation (subject to clause (e) below) and (y) no Default shall have occurred and be continuing after giving effect to such merger, and (e) any Material Subsidiary may merge with El Paso if El Paso is the surviving corporation.

SECTION 6.06.Transactions with Affiliates. Neither Borrower will, nor will El Paso permit any Subsidiary to, sell or transfer any property or assets to, or purchase or acquire any property or assets from, or otherwise engage in any other transactions with, any of its Affiliates (other than its Wholly Owned Subsidiaries), except that (a) El Paso or any Subsidiary may engage in any of the foregoing transactions in the ordinary course of business at prices and on terms and conditions not less favorable to El Paso or such Subsidiary than could be obtained on an arm’s-length basis from unrelated third parties and (b) El Paso and any Subsidiary may sell Receivables pursuant to a Receivables Facility.

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SECTION 6.07.Businesses of Borrowers and MaterialSubsidiaries. Neither Borrower will, nor will El Paso permit any Material Subsidiary to, engage at any time in any business or business activity other than (a) with respect to El Paso and the Material Subsidiaries, the business conducted by them on the Effective Date and business activities reasonably incidental thereto, and (b) with respect to the Trustee, purchasing, holding title to, making payments with respect to and selling Nuclear Fuel pursuant to, and on the terms set forth in, the Trust Agreement and the Purchase Contract.

SECTION 6.08.Other Agreements. Neither Borrower will, nor will El Paso permit any Subsidiary to, permit any waiver, supplement, modification, amendment, termination or release of (i) the Trust Agreement or the Purchase Contract or (ii) the Receivables Facility Documents, in each case to the extent that any such waiver, supplement, modification, amendment, termination or release would be adverse to the Lenders in any material respect.

SECTION 6.09.Debt to Capitalization Ratio. El Paso will not permit the ratio of (i) Total Consolidated Debt to (ii) Total Consolidated Capital as of the last day of any fiscal quarter to be in excess of 0.65 to 1.00.

SECTION 6.10.Fiscal Year. Neither Borrower will, nor will El Paso permit any Subsidiary to, change the end of its fiscal year from December 31 to any other date.

ARTICLE VIIEvents of Default

In case of the happening of any of the following events (“Events of Default”):

(a)any representation or warranty made or deemed made in or in connection with any Loan Document or the borrowings or issuances of Letters of Credit hereunder, or any representation, warranty, statement or information contained in any report, certificate, financial statement or other instrument furnished pursuant to any Loan Document, shall prove to have been false or misleading in any material respect when so made, deemed made or furnished; or

(b)default shall be made in the payment of any principal of any Loan or, subject to Section 2.20(e), the reimbursement with respect to any L/C Disbursement when and as the same shall become due and payable, whether at the due date thereof or at a date fixed for prepayment thereof or by acceleration thereof or otherwise; or

(c)default shall be made in the payment of any interest on any Loan or any Fee or L/C Disbursement or any other amount (other than an amount referred to in (b) above) due under any Loan Document, when and as the same shall become due and payable, and such default shall continue unremedied for a period of five Business Days; or

(d)default in any material manner shall be made in the due observance or performance by either Borrower or any Subsidiary of any covenant, condition or agreement contained in Section 5.01(a) or 5.05 or in Article VI; or

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(e)default shall be made in the due observance or performance by either Borrower or any Subsidiary of any covenant, condition or agreement contained in any Loan Document (other than those specified in (b), (c) or (d) above) and such default shall continue unremedied for a period of 30 days after notice thereof from the Administrative Agent or any Lender to the Borrowers; or

(f)either Borrower or any Subsidiary shall (i) fail to pay any principal or interest, regardless of amount, due in respect of any Indebtedness in a principal amount in excess of $10,000,000, when and as the same shall become due and payable, or (ii) fail to observe or perform any other term, covenant, condition or agreement contained in any agreement or instrument evidencing or governing any such Indebtedness if the effect of any failure referred to in this clause (ii) is to cause, or to permit the holder or holders of such Indebtedness or a trustee on its or their behalf (with or without the giving of notice, the lapse of time or both) to cause, such Indebtedness to become due prior to its stated maturity; or

(g)an involuntary proceeding shall be commenced or an involuntary petition shall be filed in a court of competent jurisdiction seeking (i) relief in respect of either Borrower or any Material Subsidiary or of a substantial part of the property or assets of either Borrower or any such Material Subsidiary, under Title 11 of the United States Code, as now constituted or hereafter amended, or any other Federal, state or foreign bankruptcy, insolvency, receivership or similar law, (ii) the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for either Borrower or any Material Subsidiary or for a substantial part of the property or assets of either Borrower or any such Material Subsidiary or (iii) the winding-up or liquidation of either Borrower or any Material Subsidiary; and such proceeding or petition shall continue undismissed for 60 days or an order or decree approving or ordering any of the foregoing shall be entered; or

(h)either Borrower or any Material Subsidiary shall (i) voluntarily commence any proceeding or file any petition seeking relief under Title 11 of the United States Code, as now constituted or hereafter amended, or any other Federal, state or foreign bankruptcy, insolvency, receivership or similar law, (ii) consent to the institution of, or fail to contest in a timely and appropriate manner, any proceeding or the filing of any petition described in (g) above, (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator, conservator or similar official for either Borrower or any such Material Subsidiary or for a substantial part of the property or assets of either Borrower or any such Material Subsidiary, (iv) file an answer admitting the material allegations of a petition filed against it in any such proceeding, (v) make a general assignment for the benefit of creditors, (vi) become unable, admit in writing its inability or fail generally to pay its debts as they become due or (vii) take any action for the purpose of effecting any of the foregoing; or

(i)one or more judgments for the payment of money in an aggregate amount in excess of $10,000,000 shall be rendered against either Borrower or any Subsidiary and the same shall remain undischarged for a period of 30 consecutive days during which execution shall not be effectively stayed, or any action shall be legally taken by a judgment creditor to levy upon assets or properties of either Borrower or any Subsidiary to enforce any such judgment; or

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(j)an ERISA Event shall have occurred that, in the opinion of the Required Lenders, when taken together with all other such ERISA Events, would reasonably be expected to result in liability of El Paso and its ERISA Affiliates in an aggregate amount exceeding $10,000,000 or requires payments exceeding $5,000,000 in any year; or

(k)there shall have occurred a Change in Control; or

(l)a Purchase Contract Default shall have occurred and be continuing;

then, and in every such event (other than an event with respect to either Borrower described in paragraph (g) or (h) above), and at any time thereafter during the continuance of such event, the Administrative Agent shall at the request, or may with the consent, of the Required Lenders, by notice to the Borrowers, take either or both of the following actions, at the same or different times: (i) terminate forthwith the Commitments and (ii) declare the Loans then outstanding to be forthwith due and payable in whole or in part, whereupon the principal of the Loans so declared to be due and payable, together with accrued interest thereon and any unpaid accrued Fees and all other liabilities of each Borrower accrued hereunder and under any other Loan Document, shall become forthwith due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by each Borrower, anything contained herein or in any other Loan Document to the contrary notwithstanding; and in any event with respect to either Borrower described in paragraph (g) or (h) above, the Commitments shall automatically terminate and the principal of the Loans then outstanding, together with accrued interest thereon and any unpaid accrued Fees and all other liabilities of each Borrower accrued hereunder and under any other Loan Document, shall automatically become due and payable, without presentment, demand, protest or any other notice of any kind, all of which are hereby expressly waived by each Borrower, anything contained herein or in any other Loan Document to the contrary notwithstanding.

ARTICLE VIIIThe Administrative Agent

In order to expedite the transactions contemplated by this Agreement, JPMorgan is hereby appointed to act as Administrative Agent on behalf of the Lenders and the Issuing Bank. Each of the Lenders and each assignee of any such Lender hereby irrevocably authorizes the Administrative Agent to take such actions on behalf of such Lender or assignee or the Issuing Bank and to exercise such powers as are specifically delegated to the Administrative Agent by the terms and provisions hereof and of the other Loan Documents, together with such actions and powers as are reasonably incidental thereto. The Administrative Agent is hereby expressly authorized by the Lenders and the Issuing Bank, without hereby limiting any implied authority, (a) to receive on behalf of the Lenders and the Issuing Bank all payments of principal of and interest on the Loans, all payments in respect of L/C Disbursements and all other amounts due to the Lenders hereunder, and promptly to distribute to each Lender or the Issuing Bank its proper share of each payment so received; (b) to give notice on behalf of each of the Lenders to the Borrowers of any Event of Default specified in this Agreement of which the Administrative Agent has actual knowledge acquired in connection with its agency hereunder; and (c) to distribute to each Lender copies of all notices, financial statements and other materials delivered

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by either Borrower pursuant to this Agreement or the other Loan Documents as received by the Administrative Agent.

Neither the Administrative Agent nor any of its directors, officers, employees or agents shall be liable as such for any action taken or omitted by any of them except for its or his own gross negligence or willful misconduct, or be responsible for any statement, warranty or representation herein or the contents of any document delivered in connection herewith, or be required to ascertain or to make any inquiry concerning the performance or observance by each Borrower or any other Loan Party of any of the terms, conditions, covenants or agreements contained in any Loan Document. The Administrative Agent shall not be responsible to the Lenders for the due execution, genuineness, validity, enforceability or effectiveness of this Agreement, any other Loan Document, or any other document, instrument or agreement. The Administrative Agent shall in all cases be fully protected in acting, or refraining from acting, in accordance with written instructions signed by the Required Lenders and, except as otherwise specifically provided herein, such instructions and any action or inaction pursuant thereto shall be binding on all the Lenders. The Administrative Agent shall, in the absence of knowledge to the contrary, be entitled to rely on any instrument or document believed by it in good faith to be genuine and correct and to have been signed or sent by the proper person or persons. Neither the Administrative Agent nor any of its directors, officers, employees or agents shall have any responsibility to either Borrower on account of the failure of or delay in performance or breach by any Lender or the Issuing Bank of any of its obligations hereunder or to any Lender or the Issuing Bank on account of the failure of or delay in performance or breach by any other Lender or the Issuing Bank or either Borrower of any of their respective obligations hereunder or under any other Loan Document or in connection herewith or therewith. The Administrative Agent may execute any and all duties hereunder by or through agents or employees and shall be entitled to rely upon the advice of legal counsel selected by it with respect to all matters arising hereunder and shall not be liable for any action taken or suffered in good faith by it in accordance with the advice of such counsel.

The Lenders hereby acknowledge that (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties, regardless of whether a Default has occurred and is continuing and (b) the Administrative Agent shall not be under any duty to take any discretionary action permitted to be taken by it pursuant to the provisions of this Agreement unless it shall be requested in writing to do so by the Required Lenders.

Subject to the appointment and acceptance of a successor Administrative Agent as provided below, the Administrative Agent may resign at any time by notifying the Lenders and the Borrowers. Upon any such resignation, the Required Lenders shall have the right to appoint a successor reasonably satisfactory to Borrower. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent which shall be a bank with an office in New York, New York, having a combined capital and surplus of at least $500,000,000 or an Affiliate of any such bank. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor bank, such successor shall succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent and the retiring Administrative Agent shall be discharged from its duties and obligations

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hereunder. After the Administrative Agent’s resignation hereunder, the provisions of this Article and Section 10.05 shall continue in effect for its benefit in respect of any actions taken or omitted to be taken by it while it was acting as Administrative Agent.

With respect to the Loans made by it hereunder, the Administrative Agent in its individual capacity and not as Administrative Agent shall have the same rights and powers as any other Lender and may exercise the same as though it were not an Administrative Agent, and the Administrative Agent and its Affiliates may accept deposits from, lend money to and generally engage in any kind of business with either Borrower or any Subsidiary or other Affiliates thereof as if it were not an Administrative Agent.

Each Lender agrees (a) to reimburse the Administrative Agent, on demand, in the amount of its Applicable Percentage of any expenses incurred for the benefit of the Lenders by the Administrative Agent, including counsel fees and compensation of agents and employees paid for services rendered on behalf of the Lenders, that shall not have been reimbursed by the Borrowers and (b) to indemnify and hold harmless the Administrative Agent and any of its directors, officers, employees or agents, on demand, in the amount of such pro rata share, from and against any and all liabilities, taxes, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by or asserted against it in its capacity as Administrative Agent or any of them in any way relating to or arising out of this Agreement or any other Loan Document or any action taken or omitted by it or any of them under this Agreement or any other Loan Document, to the extent the same shall not have been reimbursed by the Borrowers, provided that no Lender shall be liable to the Administrative Agent or any such other indemnified person for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements that are determined by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of the Administrative Agent or any of its directors, officers, employees or agents.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement or any other Loan Document, any related agreement or any document furnished hereunder or thereunder.

ARTICLE IXGuarantee

As a result of the arrangements contemplated by the Trust Agreement and the Purchase Contract for the financing by the Trustee of Nuclear Fuel, El Paso acknowledges that it will derive substantial benefit from the commitments of the Lenders to make Loans to the Trustee and the commitment of the Issuing Bank to issue Letters of Credit for the account of the Trustee. To induce the Lenders to make the Loans and the Issuing Bank to issue Letters of

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Credit and to enter into this Agreement, El Paso agrees with each Lender, the Issuing Bank, the Syndication Agent and the Administrative Agent (each such person, together with its successors and assigns, a “Guaranteed Party”) as follows:

SECTION 9.01.Guarantee. El Paso unconditionally guarantees, as a primary obligor and not merely as a surety, (a) the due and punctual payment of (i) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding) on the Loans made to the Trustee, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, (ii) each payment required to be made by the Trustee under this Agreement in respect of any Letter of Credit, when and as due, including payments in respect of reimbursement of disbursements, interest thereon and obligations to provide cash collateral and (iii) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of the Trustee to the Guaranteed Parties under this Agreement and the other Loan Documents and (b) the due and punctual performance of all covenants, agreements, obligations and liabilities of the Trustee under or pursuant to this Agreement and the other Loan Documents (all the monetary and other obligations referred to in the preceding clauses (a) and (b) being collectively called the “Trust Obligations”). El Paso further agrees that the Trust Obligations may be extended or renewed, in whole or in part, without notice to or further assent from it, and that it will remain bound upon its guarantee notwithstanding any extension or renewal of any Trust Obligation.

SECTION 9.02.Obligations Not Waived. To the fullest extent permitted by applicable law, El Paso waives presentment to, demand of payment from and protest to the Trustee of any of the Trust Obligations, and also waives notice of acceptance of its guarantee and notice of protest for nonpayment. To the fullest extent permitted by applicable law, the obligations of El Paso hereunder shall not be affected by (a) the failure of the Administrative Agent or any other Guaranteed Party to assert any claim or demand or to enforce or exercise any right or remedy against the Trustee, (b) any rescission, waiver, amendment or modification of, or any release from any of the terms or provisions of this Agreement, any other Loan Document, any Guarantee or any other agreement, including with respect to any other guarantor of the Trust Obligations or (c) any release or substitution of any one or more endorsers, other guarantors or other obligors of all or any portion of the Trust Obligations.

SECTION 9.03.Guarantee of Payment. El Paso further agrees that its guarantee constitutes a guarantee of payment when due and not of collection, and waives any right to require that any resort be had by the Administrative Agent or any other Guaranteed Party to any of the security held for payment of the Trust Obligations or to any balance of any deposit account or credit on the books of the Administrative Agent or any other Guaranteed Party in favor of the Trustee or any other person.

SECTION 9.04.No Discharge or Diminishment of Guarantee. The obligations of El Paso hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason (other than the payment in full in cash of the Trust Obligations), including any

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claim of waiver, release, surrender, alteration or compromise of any of the Trust Obligations, and shall not be subject to any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the Trust Obligations or otherwise. Without limiting the generality of the foregoing, the obligations of El Paso hereunder shall not be discharged or impaired or otherwise affected by the failure of the Administrative Agent or any other Guaranteed Party to assert any claim or demand or to enforce any remedy under this Agreement, any other Loan Document or any other agreement, by any waiver or modification of any provision of any thereof, by any default, failure or delay, willful or otherwise, in the performance of the Trust Obligations, or by any other act or omission that may or might in any manner or to any extent vary the risk of El Paso or that would otherwise operate as a discharge of El Paso as a matter of law or equity (other than the payment in full in cash of all the Trust Obligations).

SECTION 9.05.Defenses of the Trustee Waived. To the fullest extent permitted by applicable law, El Paso waives any defense based on or arising out of any defense of the Trustee or the unenforceability of the Trust Obligations or any part thereof from any cause, or the cessation from any cause of the liability of the Trustee, other than the payment in full in cash of the Trust Obligations. The Administrative Agent and the other Guaranteed Parties may, at their election, foreclose on any security held by one or more of them by one or more judicial or nonjudicial sales, accept an assignment of any such security in lieu of foreclosure, compromise or adjust any part of the Trust Obligations, make any other accommodation with the Trustee or any other guarantor or exercise any other right or remedy available to them against the Trustee or any other guarantor, without affecting or impairing in any way the liability of El Paso hereunder except to the extent the Trust Obligations have been fully, finally paid in cash. To the fullest extent permitted by applicable law, El Paso waives any defense arising out of any such election even though such election operates, pursuant to applicable law, to impair or to extinguish any right of reimbursement or subrogation or other right or remedy of El Paso against the Trustee or any other guarantor, as the case may be, or any security.

SECTION 9.06.Agreement to Pay; Subrogation. In furtherance of the foregoing and not in limitation of any other right that the Administrative Agent or any other Guaranteed Party has at law or in equity against El Paso by virtue hereof, upon the failure of the Trustee to pay any Trust Obligation when and as the same shall become due, whether at maturity, by acceleration, after notice of prepayment or otherwise, El Paso hereby promises to and will forthwith pay, or cause to be paid, to the Administrative Agent or such other Guaranteed Party as designated thereby in cash the amount of such unpaid Trust Obligations. Upon payment by El Paso of any sums to the Administrative Agent or any Guaranteed Party as provided above, all rights of El Paso against the Trustee arising as a result thereof by way of right of subrogation, contribution, reimbursement, indemnity or otherwise shall in all respects be subordinate and junior in right of payment to the prior payment in full in cash of all the Trust Obligations. In addition, any indebtedness of the Trustee now or hereafter held by El Paso is hereby subordinated in right of payment to the prior payment in full of the Trust Obligations. If any amount shall erroneously be paid to El Paso on account of (i) such subrogation, contribution, reimbursement, indemnity or similar right or (ii) any such indebtedness of the Trustee, such amount shall be held in trust for the benefit of the Guaranteed Parties and shall forthwith be paid to the Administrative Agent to be credited against the payment of the Trust Obligations, whether matured or unmatured, in accordance with the terms of the Loan Documents.

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SECTION 9.07.Information. El Paso assumes all responsibility for being and keeping itself informed of the Trustee’s financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Trust Obligations and the nature, scope and extent of the risks that El Paso assumes and incurs hereunder, and agrees that none of the Administrative Agent or the other Guaranteed Parties will have any duty to advise El Paso of information known to it or any of them regarding such circumstances or risks.

SECTION 9.08.Termination. The guarantee made hereunder (a) shall terminate when all the Trust Obligations have been indefeasibly paid in full and the Lenders have no further commitment to lend to the Trustee under this Agreement, the Trustee L/C Exposure has been reduced to zero and the Issuing Bank has no further obligation to issue Letters of Credit under this Agreement and (b) shall continue to be effective or be reinstated, as the case may be, if at any time payment, or any part thereof, of any Trust Obligation is rescinded or must otherwise be restored by any Guaranteed Party or El Paso upon the bankruptcy or reorganization of the Trustee, El Paso or otherwise.

ARTICLE XMiscellaneous

SECTION 10.01.Notices.

(a)Notices Generally. Except as provided in paragraph (b) below, all notices and other communications provided for herein shall be in writing and shall be delivered by hand or overnight courier service, mailed by certified or registered mail or sent by telecopier as follows:

(i) if to either Borrower, to it in care of El Paso Electric Company, Stanton Tower, 100 N. Stanton, El Paso, Texas 79901, Attention of: General Counsel (Telecopier No. (915) 521-4729);

(ii) if to the Administrative Agent or the Issuing Bank, to JPMorgan Chase Bank, N.A., Loan and Agency Services Group, 1111 Fannin Street, 10th Floor, Houston, TX 77002, Attention of: Maria Arredondo (Telecopier No. (713) 750-2358), with a copy to JPMorgan Chase Bank, N.A., at 201 E. Main, 3rd Floor, El Paso, TX 79901, Attention of: Paul S. Condie (Telecopier No. (915) 546-6575); and

(iii) if to a Lender, to it at its address (or telecopier number) set forth on Schedule 2.01, in the Assignment and Acceptance pursuant to which such Lender shall have become a party hereto (or in its Administrative Questionnaire, as the case may be) or, in the case of an Augmenting Lender, in the documentation executed by such Augmenting Lender pursuant to Section 2.21(a).

Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by telecopier shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the

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recipient). Notices delivered through electronic communications to the extent provided in paragraph (b) below shall be effective as provided in said paragraph (b).

(b)Electronic Communications. Notices and other communications to the Lenders and the Issuing Bank hereunder may be delivered or furnished by electronic communication (including e‑mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent, provided that the foregoing shall not apply to notices to any Lender or the Issuing Bank pursuant to Article II if such Lender or the Issuing Bank, as applicable, has notified the Administrative Agent that it is incapable of receiving notices under such Article by electronic communication. The Administrative Agent or either Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications.

Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next business day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

(c)Change of Address, Etc. Any party hereto may change its address or telecopier number for notices and other communications hereunder by notice to the other parties hereto.

SECTION 10.02.Survival of Agreement. All covenants, agreements, representations and warranties made by each Borrower herein and in the certificates or other instruments prepared or delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the Lenders and the Issuing Bank and shall survive the making by the Lenders of the Loans and the issuance of Letters of Credit by the Issuing Bank, regardless of any investigation made by the Lenders or the Issuing Bank or on their behalf, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any Fee or any other amount payable under this Agreement or any other Loan Document is outstanding and unpaid or any Letter of Credit is outstanding (for which sufficient cash collateral has not been deposited with the Administrative Agent) and so long as the Commitments have not been terminated. The provisions of Sections 2.12 (except as expressly limited therein), 2.14, 2.18 and 10.05 shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the expiration of the Commitments, the expiration of any Letter of Credit, the invalidity or unenforceability of any term or provision of this Agreement or any other Loan Document, or any investigation made by or on behalf of the Administrative Agent, any Lender or the Issuing Bank.

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SECTION 10.03.Binding Effect. This Agreement shall become effective when it shall have been executed by the Borrowers and the Administrative Agent and when the Administrative Agent shall have received counterparts hereof which, when taken together, bear the signatures of each of the other parties hereto.

SECTION 10.04.Successors and Assigns. (a) Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the permitted successors and assigns of such party; and all covenants, promises and agreements by or on behalf of each Borrower, the Administrative Agent, the Issuing Bank or the Lenders that are contained in this Agreement shall bind and inure to the benefit of their respective successors and assigns.

(b)Each Lender may assign to one or more assignees all or a portion of its interests, rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans at the time owing to it); provided, however, that (i) except in the case of an assignment to a Lender or an Affiliate of a Lender, (x) El Paso must give its prior written consent to such assignment (which consent shall not be unreasonably withheld) and (y) the amount of the Commitment of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 (or, if less, the entire remaining amount of such Lender’s Commitment), providedfurther that during the continuation of an Event of Default, the consent of El Paso shall not be required for such assignment, (ii) all assignments shall require the prior written consent of the Administrative Agent and the Issuing Bank (which consents shall not be unreasonably withheld), (iii) each such assignment shall be of a constant, and not a varying, percentage of all the assigning Lender’s rights and obligations under this Agreement, (iv) the parties to each such assignment shall execute and deliver to the Administrative Agent an Assignment and Acceptance, together with a processing and recordation fee of $3,500, and (v) the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire. Upon acceptance and recording pursuant to paragraph (e) of this Section 10.04, from and after the effective date specified in each Assignment and Acceptance, which effective date shall be at least five Business Days after the execution thereof, (A) the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement and (B) the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all or the remaining portion of an assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.12 (except as expressly limited therein), 2.14, 2.18 and 10.05, as well as to any Fees accrued for its account and not yet paid).

(c)By executing and delivering an Assignment and Acceptance, the assigning Lender thereunder and the assignee thereunder shall be deemed to confirm to and agree with each other and the other parties hereto as follows: (i) such assigning Lender warrants that it is the legal and beneficial owner of the interest being assigned thereby free and clear of any adverse claim and that its Commitment, and the outstanding balance of its Loans, in each case without giving effect to assignments thereof which have not become effective, are as set forth in such Assignment and Acceptance, (ii) except as set forth in (i) above, such assigning Lender makes no

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representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with this Agreement, or the execution, legality, validity, enforceability, genuineness, sufficiency or value of this Agreement, any other Loan Document or any other instrument or document furnished pursuant hereto, or the financial condition of the Borrowers or the performance or observance by either Borrower of any of its obligations under this Agreement, any other Loan Document or any other instrument or document furnished pursuant hereto; (iii) such assignee represents and warrants that it is legally authorized to enter into such Assignment and Acceptance; (iv) such assignee confirms that it has received a copy of this Agreement, together with copies of the most recent financial statements referred to in Section 3.05 or delivered pursuant to Section 5.04 and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Assignment and Acceptance; (v) such assignee will independently and without reliance upon the Administrative Agent, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement; (vi) such assignee appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto; and (vii) such assignee agrees that it will perform in accordance with their terms all the obligations which by the terms of this Agreement are required to be performed by it as a Lender.

(d)Notwithstanding Section 2.04, the Administrative Agent, acting for this purpose as an agent of the Borrowers, shall maintain at one of its offices in The City of New York a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitment of, and principal amount of the Loans owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive and the Borrowers, the Administrative Agent, the Issuing Bank and the Lenders may treat each person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by each Borrower, the Issuing Bank and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(e)Upon its receipt of a duly completed Assignment and Acceptance executed by an assigning Lender and an assignee, an Administrative Questionnaire completed in respect of the assignee (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in paragraph (b) above and, if required, the written consent of each Borrower, the Issuing Bank and the Administrative Agent to such assignment, the Administrative Agent shall (i) accept such Assignment and Acceptance, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Lenders and the Issuing Bank. No assignment shall be effective unless it has been recorded in the Register as provided in this paragraph (e).

(f)Each Lender may without the consent of the Borrowers, the Issuing Bank or the Administrative Agent sell participation interests to one or more banks or other entities in all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Loans owing to it); provided, however, that (i) such Lender’s obligations

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under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) the participating banks or other entities shall be entitled to the benefit of the cost protection provisions contained in Sections 2.12, 2.14 and 2.18 (subject to the requirements and limitations therein, including the requirements under Section 2.18(f) (it being understood that the documentation required under Section 2.18(f) shall be delivered to the participating Lender)) to the same extent as if they were Lenders, provided, however, that the holder of a participation agrees to be subject to the provisions of Sections 2.15, 2.16, 2.17, 2.18(g) and 2.19 as if it were an assignee and the right of each holder of a participation to receive payment under Sections 2.12, 2.14 and 2.18 shall be limited to the lesser of (a) the amounts actually incurred by such holder for which payment is provided under said sections and (b) the amounts that would have been payable under said sections by the applicable Borrower to the Lender granting the participation to such holder had such participation not been granted, (iv) the Borrowers, the Administrative Agent, the Issuing Bank and the Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement, and such Lender shall retain the sole right to enforce the obligations of the Borrowers relating to the Loans or L/C Disbursements and to approve any amendment, modification or waiver of any provision of this Agreement (other than amendments, modifications or waivers decreasing any fees payable hereunder or the amount of principal of or the rate at which interest is payable on the Loans, extending any scheduled principal payment date or date fixed for the payment of interest on the Loans or increasing or extending the Commitments) and (v) without the prior written consent of the Administrative Agent, no participation shall be sold to a prospective participant that bears a relationship to either Borrower described in Section 108(e)(4) of the Code. Each Lender that sells a participation shall, acting solely for this purpose as an non-fiduciary agent of the Borrowers, maintain at one of its offices in the United States a register on which it enters the name and address of each of its participants and the principal amounts (and stated interest) of each such participant’s interest in the Loans or other obligations under this Agreement and the other Loan Documents (the “Participant Register”). The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary

(g)Any Lender or participant may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 10.04, disclose to the assignee or participant or proposed assignee or participant any information relating to the Borrowers furnished to such Lender by or on behalf of the Borrowers; provided that, prior to any such disclosure of information designated by the Borrowers as confidential, each such assignee or participant or proposed assignee or participant shall execute an agreement whereby such assignee or participant shall agree (subject to customary exceptions) to preserve the confidentiality of such confidential information on terms no less restrictive than those applicable to the Lenders pursuant to Section 10.16.

(h)Any Lender may at any time assign all or any portion of its rights under this Agreement to a Federal Reserve Bank to secure extensions of credit by such Federal Reserve Bank to such Lender; provided that no such assignment shall release a Lender from any of its obligations hereunder or substitute any such Bank for such Lender as a party hereto. In order to facilitate such an assignment to a Federal Reserve Bank, each Borrower shall, at the request of

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the assigning Lender, duly execute and deliver to the assigning Lender a promissory note or notes evidencing the Loans made to such Borrower by the assigning Lender hereunder.

(i)Neither Borrower shall assign or delegate any of its rights or duties hereunder without the prior written consent of the Administrative Agent, the Issuing Bank and each Lender, and any attempted assignment without such consent shall be null and void.

(j)In the event that S&P, Moody’s and Thompson’s BankWatch (or InsuranceWatch Ratings Service, in the case of Lenders that are insurance companies (or Best’s Insurance Reports, if such insurance company is not rated by Insurance Watch Ratings Service)) shall, after the date that any Lender becomes a Lender, downgrade the long-term certificate of deposit ratings of such Lender, and the resulting ratings shall be below BBB-, Baa3 and C (or BB, in the case of a Lender that is an insurance company (or B, in the case of an insurance company not rated by InsuranceWatch Ratings Service)), respectively, then the Issuing Bank shall have the right, but not the obligation, at its own expense, upon notice to such Lender and the Administrative Agent, to replace (or to request the Borrowers to use their reasonable efforts to replace) such Lender with an assignee (in accordance with and subject to the restrictions contained in paragraph (b) above), and such Lender hereby agrees to transfer and assign without recourse (in accordance with and subject to the restrictions contained in paragraph (b) above) all its interests, rights and obligations in respect of its Commitment to such assignee; provided, however, that (i) no such assignment shall conflict with any law, rule and regulation or order of any Governmental Authority and (ii) the Issuing Bank or such assignee, as the case may be, shall pay to such Lender in immediately available funds on the date of such assignment the principal of and interest accrued to the date of payment on the Loans made by such Lender hereunder and all other amounts accrued for such Lender’s account or owed to it hereunder.

SECTION 10.05.Expenses; Indemnity. (a) Each Borrower jointly and severally agrees to pay all reasonable out-of-pocket expenses incurred by the Administrative Agent, the Syndication Agent and the Issuing Bank in connection with the syndication of the credit facilities provided for herein and the preparation and administration of this Agreement and the other Loan Documents or in connection with any amendments, modifications or waivers of the provisions hereof or thereof (whether or not the transactions hereby or thereby contemplated shall be consummated) or incurred by the Administrative Agent, the Syndication Agent or any Lender in connection with the enforcement or protection of its rights in connection with this Agreement and the other Loan Documents or in connection with the Loans made or Letters of Credit issued hereunder, including the reasonable fees, charges and disbursements of (i) Cravath, Swaine & Moore LLP, counsel for the Administrative Agent, (ii) Hughes Hubbard & Reed LLP, counsel for the Syndication Agent, (iii) one local counsel to the Administrative Agent per material jurisdiction deemed necessary by the Administrative Agent and (iv) if necessary, one special counsel to the Administrative Agent per regulatory regime, and, in connection with any such enforcement or protection, the reasonable fees, charges and disbursements of any other counsel for the Administrative Agent, the Syndication Agent or any Lender.

(b)Each Borrower jointly and severally agrees to indemnify the Administrative Agent, the Syndication Agent, each Lender and the Issuing Bank, each Affiliate of any of the foregoing persons and each of their respective directors, officers, employees and agents (each such person being called an “Indemnitee”) against, and to hold each Indemnitee

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harmless from, any and all losses, claims, damages, liabilities and related expenses, including reasonable counsel fees, charges and disbursements, incurred by or asserted against any Indemnitee arising out of, in any way connected with, or as a result of (i) the execution or delivery of this Agreement or any other Loan Document or any agreement or instrument contemplated thereby, the performance by the parties thereto of their respective obligations thereunder or the consummation of the Transactions and the other transactions contemplated thereby, (ii) the use of the proceeds of the Loans or issuance of Letters of Credit, (iii) any claim, litigation, investigation or proceeding relating to any of the foregoing, whether or not any Indemnitee is a party thereto, (iv) any actual or alleged presence or Release of Hazardous Materials on any property owned or operated by either Borrower or any Subsidiary, or any Environmental Claim related in any way to either Borrower or any Subsidiary or (v) any strict liability or liability without fault or other liability of an owner or vendor relating in any way to the Nuclear Fuel, whether arising out of statute, judicial decision or otherwise; provided that such indemnity shall not, as to any Indemnitee, be available to the extent that such losses, claims, damages, liabilities or related expenses are determined by a court of competent jurisdiction to have resulted from the gross negligence or willful misconduct of such Indemnitee.

(b)The provisions of this Section 10.05 shall remain operative and in full force and effect regardless of the expiration of the term of this Agreement, the consummation of the transactions contemplated hereby, the repayment of any of the Loans, the expiration of the Commitments, the expiration of any Letter of Credit, the invalidity or unenforceability of any term or provision of this Agreement or any other Loan Document, or any investigation made by or on behalf of the Administrative Agent, any Lender or the Issuing Bank. All amounts due under this Section 10.05 shall be payable on written demand therefor.

SECTION 10.06.Right of Setoff. If an Event of Default shall have occurred and be continuing, each Lender is hereby authorized at any time and from time to time, to the extent not prohibited by applicable law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of either Borrower against any of and all the Obligations now or hereafter existing under this Agreement and the other Loan Documents held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement or such other Loan Document and although such obligations may be unmatured. The rights of each Lender under this Section 10.06 are in addition to other rights and remedies (including other rights of setoff) which such Lender may have.

SECTION 10.07.Applicable Law. THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS (OTHER THAN LETTERS OF CREDIT) SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK. EACH LETTER OF CREDIT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED IN ACCORDANCE WITH, THE LAWS OR RULES DESIGNATED IN SUCH LETTER OF CREDIT, OR IF NO SUCH LAWS OR RULES ARE DESIGNATED, THE UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS MOST RECENTLY PUBLISHED AND IN EFFECT, ON THE DATE SUCH LETTER OF CREDIT WAS ISSUED, BY THE INTERNATIONAL CHAMBER OF COMMERCE (THE “UNIFORMCUSTOMS”) AND,

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AS TO MATTERS NOT GOVERNED BY THE UNIFORM CUSTOMS, THE LAWS OF THE STATE OF NEW YORK.

SECTION 10.08.Waivers; Amendment. (a) No failure or delay of the Administrative Agent, any Lender or the Issuing Bank in exercising any power or right hereunder or under any other Loan Document shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent, the Issuing Bank and the Lenders hereunder and under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or any other Loan Document or consent to any departure by either Borrower therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) below, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. No notice or demand on the Borrowers in any case shall entitle either Borrower to any other or further notice or demand in similar or other circumstances.

(b)Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to an agreement or agreements in writing entered into by the Borrowers and the Required Lenders; provided, however, that no such agreement shall (i) decrease the principal amount of, or extend the maturity of or any scheduled principal payment date or date for the payment of any interest on any Loan or any date for reimbursement of an L/C Disbursement, or waive or excuse any such payment or any part thereof, or decrease the rate of interest on any Loan or L/C Disbursement, without the prior written consent of each Lender directly and adversely affected thereby, (ii) increase or extend the Commitment of any Lender without the prior written consent of such Lender, (iii) decrease the Commitment Fees or L/C Participation Fees of any Lender, or extend the date of payment of such fees, without the prior written consent of such Lender, (iv) amend or modify the pro rata sharing requirements of Section 2.15 without the prior written consent of each Lender (it being understood and agreed that “amend and extend” transactions which provide for different interest rates and fees for extending Lenders shall only require the consent of the extending Lenders and the Required Lenders), (v) amend or modify the provisions of this Section 10.08 or Section 10.04(i) or the definition of the term “Required Lenders” without the prior written consent of each Lender, or (vi) release El Paso from its guarantee hereunder or release any Subsidiary from any guarantee of the El Paso Obligations, without the prior written consent of each Lender; provided further, however, that no such agreement shall amend, modify or otherwise affect the rights or duties of the Administrative Agent, the Syndication Agent or the Issuing Bank hereunder or under any other Loan Document without the prior written consent of the Administrative Agent, the Syndication Agent or the Issuing Bank, respectively.

SECTION 10.09.Interest Rate Limitation. Notwithstanding anything herein to the contrary, if at any time the interest rate applicable to any Loan or L/C Disbursement, together with all fees, charges and other amounts which are treated as interest on such Loan or L/C Disbursement under applicable law (collectively the “Charges”), shall exceed the maximum lawful rate (the “Maximum Rate”) which may be contracted for, charged, taken, received or reserved by the Lender holding such Loan or the Issuing Bank in accordance with applicable

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law, the rate of interest payable in respect of such Loan or L/C Disbursement hereunder, together with all Charges payable in respect thereof, shall be limited to the Maximum Rate and, to the extent lawful, the interest and Charges that would have been payable in respect of such Loan or L/C Disbursement but were not payable as a result of the operation of this Section 10.09 shall be cumulated and the interest and Charges payable to such Lender in respect of other Loans or L/C Disbursements or periods shall be increased (but not above the Maximum Rate therefor) until such cumulated amount, together with interest thereon at the Federal Funds Effective Rate to the date of repayment, shall have been received by such Lender; provided that at any time Texas law shall establish the Maximum Rate, the Maximum Rate shall be the “weekly ceiling” (formerly known as the indicated (weekly) rate ceiling in Article 1.04, Subtitle 1, Title 79, of the Revised Civil Statutes of Texas, as amended) described in and computed in accordance with Chapter 303 of the Texas Finance Code, as amended; provided further that, to the extent permitted by such Article, the Administrative Agent may from time to time by notice to each Borrower revise the election of such interest rate ceiling as such ceiling affects then current or future balances of the Loans.

SECTION 10.10.Entire Agreement. THIS AGREEMENT, THE FEE LETTER AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE CONTRACT BETWEEN THE PARTIES RELATIVE TO THE SUBJECT MATTER HEREOF. ANY OTHER PREVIOUS AGREEMENT AMONG THE PARTIES WITH RESPECT TO THE SUBJECT MATTER HEREOF IS SUPERSEDED BY THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS. NOTHING IN THIS AGREEMENT OR IN THE OTHER LOAN DOCUMENTS, EXPRESSED OR IMPLIED, IS INTENDED TO CONFER UPON ANY PARTY OTHER THAN THE PARTIES HERETO AND THERETO ANY RIGHTS, REMEDIES, OBLIGATIONS OR LIABILITIES UNDER OR BY REASON OF THIS AGREEMENT OR THE OTHER LOAN DOCUMENTS.

SECTION 10.11.Waiver of Jury Trial. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR ANY OF THE OTHER LOAN DOCUMENTS. EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS APPLICABLE, BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 10.11.

SECTION 10.12.Severability. In the event any one or more of the provisions contained in this Agreement or in any other Loan Document should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein and therein shall not in any way be affected or impaired thereby (it being understood that the invalidity of a particular provision in a particular jurisdiction shall not in and

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of itself affect the validity of such provision in any other jurisdiction). The parties shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

SECTION 10.13.Counterparts. This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original but all of which when taken together shall constitute a single contract, and shall become effective as provided in Section 10.03. Delivery of an executed signature page to this Agreement by facsimile or other electronic transmission (including, without limitation, by Adobe portable document format file (also known as a “PDF” file)) shall be as effective as delivery of a manually signed counterpart of this Agreement.

SECTION 10.14.Headings. Article and Section headings and the Table of Contents used herein are for convenience of reference only, are not part of this Agreement and are not to affect the construction of, or to be taken into consideration in interpreting, this Agreement.

SECTION 10.15.Jurisdiction; Consent to Service of Process. (a) Each Borrower hereby irrevocably and unconditionally submits, for itself and its property, to the exclusive jurisdiction of any New York State court or Federal court of the United States of America sitting in New York City, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or the other Loan Documents, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent, the Issuing Bank or any Lender may otherwise have to bring any action or proceeding relating to this Agreement or the other Loan Documents against either Borrower or its respective properties in the courts of any jurisdiction.

(b)Each Borrower hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the other Loan Documents in any New York State or Federal court. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(c)Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 10.01. Nothing in this Agreement or any other Loan Document will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

SECTION 10.16.Confidentiality. The Administrative Agent, the Issuing Bank and each of the Lenders agrees to keep confidential (and to use its best efforts to cause its

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respective agents and representatives to keep confidential) the Information (as defined below) and all copies thereof, extracts therefrom and analyses or other materials based thereon, except that the Administrative Agent, the Issuing Bank or any Lender shall be permitted to disclose Information (a) to such of its respective officers, directors, employees, agents, affiliates and representatives as need to know such Information, (b) to the extent requested by any regulatory authority, (c) to the extent otherwise required by applicable laws and regulations or by any subpoena or similar legal process, (d) in connection with any suit, action or proceeding relating to the enforcement of its rights hereunder or under the other Loan Documents, (e) to the extent such Information (i) becomes publicly available other than as a result of a breach of this Section 10.16 or (ii) becomes available to the Administrative Agent, the Issuing Bank or any Lender on a nonconfidential basis from a source other than the Borrowers, or (f) to the extent permitted by Section 10.04(g). For the purposes of this Section 10.16, “Information” shall mean all financial statements, certificates, reports, agreements and information (including all analyses, compilations and studies prepared by the Administrative Agent, the Issuing Bank or any Lender based on any of the foregoing) that are received from the Borrowers and related to the Borrowers, any shareholder of El Paso or any employee, customer or supplier of either Borrower, other than any of the foregoing that were available to the Administrative Agent, the Issuing Bank or any Lender on a nonconfidential basis prior to its disclosure thereto by either Borrower, and which are in the case of Information provided after the Original Closing Date, clearly identified at the time of delivery as confidential. The provisions of this Section 10.16 shall remain operative and in full force and effect regardless of the expiration and term of this Agreement.

SECTION 10.17.Texas Revolving Credit Statute. If, notwithstanding the provisions of Section 10.07, Texas law shall be applied by any Governmental Authority to this Agreement, the other Loan Documents or the obligations of either Borrower hereunder or thereunder, each Borrower hereby agrees that the provisions of Chapter 346 of the Texas Finance Code, as amended (formerly found in Chapter 15 of Subtitle 3, Title 79, of the Revised Civil Statutes of Texas, 1925, as amended), shall not govern or in any manner apply to its obligations hereunder or thereunder.

SECTION 10.18.No Recourse; Multiple Capacities. (a) Wherever in this Agreement or the other Loan Documents BONY has undertaken any obligations in its capacity as Trustee, it has done so solely in such capacity and not in its individual capacity. Notwithstanding any other provision of this Agreement, BONY shall not be personally liable for the obligations or liabilities of the Trustee hereunder or under any other Loan Document, except to the extent such obligations or liabilities result from BONY’s gross negligence or willful misconduct.

(b)Each party to this Agreement acknowledges that Section 6.1 of the Trust Agreement imposes limitations on the liability of BONY in its capacity as Trustee.

SECTION 10.19.Limited Representations, Warranties and Covenants of Trustee. With respect to representations and warranties contained in Article III, the affirmative covenants contained in Article V and the negative covenants contained in Article VI, it is understood and agreed that (a) the Trustee has made no independent inquiry as to (i) the assets placed in trust into the Rio Grande Resources Trust II or (ii) any facts concerning El Paso and the Subsidiaries

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or as to the status or condition of any of their assets or any disclosures made by them and (b) the Trustee’s representations, warranties and covenants are limited to itself and those matters within its control. The Trustee has no actual knowledge of any facts that would indicate that any such representations or warranties by El Paso or the Subsidiaries are untrue.

SECTION 10.20.USA Patriot Act Notice. Each Lender and each Agent (for itself and not on behalf of any Lender) hereby notifies the Borrowers that pursuant to the requirements of the USA Patriot Act, it is required to obtain, verify and record information that identifies the Borrowers, which information includes the name and address of the Borrowers and other information that will allow such Lender or such Agent, as applicable, to identify the Borrowers in accordance with the USA Patriot Act.

SECTION 10.21.Amendment and Restatement. (a) The Borrowers, the Administrative Agent, the Syndication Agent, the Issuing Bank and the Lenders hereby agree that upon the effectiveness of this Agreement, the terms and provisions of the Existing Credit Agreement shall be and hereby are amended and restated in their entirety by the terms and conditions of this Agreement and the terms and provisions of the Existing Credit Agreement, except as otherwise provided in the next paragraph, shall be superseded by this Agreement.

(b)Notwithstanding the amendment and restatement of the Existing Credit Agreement by this Agreement, the Borrowers shall continue to be liable to the Agents, the Issuing Bank, the Lenders and the other Indemnitees with respect to agreements on the part of the Borrowers under the Existing Credit Agreement to indemnify and hold harmless the Agents, the Issuing Bank, the Lenders and the other Indemnitees from and against all losses, claims, damages, liabilities, costs, charges and expenses to which the Agents, the Issuing Bank, the Lenders and the other Indemnitees may be subject arising in connection with, and as provided in, the Existing Credit Agreement. This Agreement is given as a substitution of, and not as a payment of, the obligations of the Borrowers under the Existing Credit Agreement and is not intended to constitute a novation of the Existing Credit Agreement. Upon the effectiveness of this Agreement all amounts outstanding and owing by the Borrowers under the Existing Credit Agreement as of the date hereof shall constitute obligations hereunder.

(c)By execution of this Agreement all parties hereto agree that each of the other Loan Documents is hereby amended such that all references to the Existing Credit Agreement and the obligations of the Borrowers thereunder shall be deemed to refer to this Agreement and the continuation of the Borrowers’ obligations hereunder.

[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

EL PASO ELECTRIC COMPANY

By: /s/ Steven P. Busser     Name:Steven P. Busser Title: Vice President, Treasurer

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., not in its individual capacity, but solely in its capacity as Trustee

By: /s/ Rafael Martinez    Name:Rafael Martinez Title: Senior Associate

JPMORGAN CHASE BANK, N.A., as Administrative Agent, Issuing Bank and a Lender

By: /s/ Joseph W. Mullings    Name:Joseph W. Mullings Title: Senior Vice President

UNION BANK, N.A., as Syndication Agent and a Lender

By: /s/ John Guilds    Name:John Guilds Title: Vice President

S-1

BANK OF AMERICA, N.A., as a Lender

By: /s/ Gary L. Mingle    Name: Gary L. MingleTitle: Senior Vice President

U.S. BANK NATIONAL ASSOCIATION, as a Lender

By: /s/ John Prigge    Name:John PriggeTitle: Vice President

S-2

SCHEDULE 2.01

Commitments

Lender	Address for Notices	Commitment
JPMorgan Chase Bank, N.A.	201 E. Main, 3rd Floor, El Paso, TX 79901, Attention: Paul S. Condie Facsimile: (915) 546-6575	$	62,500,000
Union Bank, N.A.	445 South Figueroa Street,15th Floor, Los Angeles, CA 90071. Attention: John Guilds Facsimile: (213) 236-4096	$	62,500,000
Bank of America, N.A.	700 Louisiana Street, 7th Floor Houston, TX 77002 Attention: Gary Mingle Facsimile: (713) 247-7748	$	37,500,000
U.S. Bank National Association	461 Fifth Avenue New York, New York 10017 Attention: Shawn O'Hara Facsimile: (646) 935-4552	$	37,500,000
Total		$	200,000,000

SCHEDULE 3.04

Governmental Approvals

FERC

On September 13, 2011, El Paso Electric Company (the “Company”) filed with the Federal Energy Regulatory Commission (“FERC”) an application seeking authority pursuant to Section 204 of the Federal Power Act to enter into the Credit Agreement and to engage in transactions related thereto. The FERC Order approving the Company's application (Docket ES11-43-000) was issued on October 13, 2011.

New Mexico Public Regulation Commission

On September 13, 2011, the Company filed with the New Mexico Public Regulation Commission (“NMPRC”) an application seeking authority pursuant to NMSA 1978 §62-6-6 to enter into the Credit Agreement and to engage in transactions related thereto. The Hearing Examiner's Recommended Decision was issued on October 13, 2011, recommending the approval of the Company's application. The NMPRC Order adopting the Hearing Examiner's Recommended Decision and approving the Company's application (Case No. 11-00349-UT) was issued on October 18, 2011.

SCHEDULE 3.07

Subsidiaries

Name of Subsidiary	State of Incorporation	% Owned by El Paso
Mirasol Energy Service, Inc.	Delaware	100%

SCHEDULE 3.08

Litigation and Compliance with Laws

Schedule 3.15 is incorporated herein by reference.

SCHEDULE 3.15

Environmental Matters

(c)Releases

The Company experiences sporadic, limited quantity releases of electric insulating oil (mineral oil) within its electric distribution and transmission system consistent with the operation of these systems. These releases are commonly cleaned and removed within regulatory accepted timeframes and are overseen by the respective environmental enforcement agencies.

In a similar manner, the generation of electricity at power plants owned and operated by the Company, may experience sporadic and limited quantity releases of chemicals common to the processes of the generation of electricity within the power plant property. These releases are commonly cleaned and removed within regulatory accepted timeframes and are overseen by the respective environmental enforcement agencies.

(d) Environmental Claims.

Four Corners

On May 7, 2010, Arizona Public Service, on behalf of the Four Corners co-owners (including the Company) (“Project Participants”), received Notice of Intent to Sue Four Corners Power Plant for Violations of the Clean Air Act (the Notice). EarthJustice sent the Notice on behalf of Diné CARE (Citizens Against Ruining our Environment), To Nizhoni Ani, National Parks Conservation Association, and the Sierra Club.

The Notice alleges two sets of Clean Air Act violations: Prevention of Significant Deterioration violations and New Source Performance Standards violations. The alleged violations concern pulverizer projects on Units 4-5 in the 1980's and boiler, turbine, generator and other projects on Units 4-5 commencing in 2007. APS is taking the lead on determining whether and how to respond to the Notice. The Project Participants have retained joint counsel and hold meetings of counsel and the Project Participants as required.

The Company recently received word that the Plaintiffs' filed a lawsuit in the United States District Court for New Mexico on October 4, 2011, though the Company has not been formally served yet. The Company is unable to predict the outcome of these discussions

In March 2009, EPA Region 9 separately sent the Project Participants a Clean Air Act § 114 request for information regarding historic projects at Four Corners. Settlement discussions among the Project Participants, the EPA and the Department of Justice are ongoing to address all outstanding environmental issues relating to Four Corners.

Casmalia

On August 12, 2010, the Company, along with many other companies, received a notice from the EPA, inviting the Company to join a settlement related to the cleanup of a Superfund site in Santa Barbara County, California as a de minimis party. The notice alleges that a former subsidiary of the Company, B.P. John Furniture Company, delivered waste to the site and has potential cleanup liability. The EPA offered to settle for the sum of approximately $39,000. The Company declined to participate in the settlement because the EPA presented no evidence that the Company delivered any waste to the site and offered no legal basis for Company liability for the obligations of its former subsidiary. The Company believes that a material adverse outcome in this matter is remote.

(e)Hazardous Materials Handling.

The Company handles, stores, transports and arranges for the proper disposal of limited and specific hazardous materials. Other waste streams including but not limited to regulated wastes, non-regulated wastes, hazardous wastes, non-hazardous wastes, and industrial wastes are handled, stored, transported and properly disposed as necessary to the operation(s) of its business.

SCHEUDLE 4.02(a)

Local Regulatory Counsel

JurisdictionCounsel

ArizonaPerkins Coie L.L.P.

New MexicoLaw Offices of Randall W. Childress, P.C.

TexasDuggins Wren Mann & Romero, LLP

a Professional Corporation

FERCGeneral Counsel of the Company.

SCHEDULE 6.02

Liens

Minor miscellaneous liens existing on the Closing Date, incurred in the ordinary course of business, none of which cover property that is material to the business, operations or financial position of the Company.

SCHEDULE 6.04

Certain Investments

1. Contributions to and interests of the Company in decommissioning trusts relating to the Palo Verde Nuclear Generating Station (“PVNG”) (to the extent such contributions and interest constitute investments) as contemplated by the ANPP Participation Agreement dated as of August 23, 1973, as amended.

2. Contributions to and interests of the Company in spent nuclear fuel trust relating to the PVNG (to the extent such contributions and interests constitute investments).

3. Investments of $4.0 million in debt securities collateralized by student loans re-insured by the Department of Education as part of the Federal Family Education Loan Program, consisting of two $2.0 million investments in auction rate securities maturing in 2042 and 2044.

4. Other minor investments which were obtained in the ordinary course of business and, in the aggregate, have a book value of less than $200,000.

EXHIBIT B

[Form of]

ASSIGNMENT AND ACCEPTANCE

Reference is made to the Amended and Restated Credit Agreement dated as of November 15, 2011 (as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among El Paso Electric Company (“El Paso”), The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II (the “Trustee”), the lenders party thereto (the “Lenders”), JPMorgan Chase Bank, N.A., as issuing bank (in such capacity, the “Issuing Bank”) and as administrative agent (in such capacity, the “Administrative Agent”) for the Lenders, and Union Bank, N.A., as syndication agent. Terms defined in the Credit Agreement are used herein with the same meanings.

1.The Assignor hereby sells and assigns, without recourse, to the Assignee, and the Assignee hereby purchases and assumes, without recourse, from the Assignor, effective as of the Assignment Effective Date set forth below (but not prior to the recordation of the information contained herein in the Register pursuant to Section 10.04(e) of the Credit Agreement), the interests set forth below (the “Assigned Interest”) in the Assignor's rights and obligations under the Credit Agreement and the other Loan Documents, including, without limitation, the amounts and percentages set forth below of (i) the Commitments of the Assignor on the Assignment Effective Date, (ii) the Loans owing to the Assignor which are outstanding on the Assignment Effective Date and (iii) participations in Letters of Credit which are outstanding on the Assignment Effective Date. Each of the Assignor and the Assignee hereby makes and agrees to be bound by all the representations, warranties and agreements set forth in Section 10.04(c) of the Credit Agreement, a copy of which has been received by each such party. From and after the Assignment Effective Date (i) the Assignee shall be a party to and be bound by the provisions of the Credit Agreement and, to the extent of the interests assigned by this Assignment and Acceptance, have the rights and obligations of a Lender thereunder and under the Loan Documents and (ii) the Assignor shall, to the extent of the interests assigned by this Assignment and Acceptance, relinquish its rights and be released from its obligations under the Credit Agreement.

2.This Assignment and Acceptance is being delivered to the Administrative Agent together with (i) the forms specified in Section 2.18(f) of the Credit Agreement, duly completed and executed by such Assignee, (ii) if the Assignee is not already a Lender under the Credit Agreement, an Administrative Questionnaire in the form of Exhibit A to the Credit Agreement and (iii) unless otherwise agreed to by the Administrative Agent, a processing and recordation fee of $3,500 pursuant to Section 10.04(b) of the Credit Agreement.

3.THIS ASSIGNMENT AND ACCEPTANCE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

B-1

Date of Assignment: .......................................................................................................................................

Legal Name of Assignor: ................................................................................................................................

Legal Name of Assignee: ...............................................................................................................................

Assignee's Address for Notices: .....................................................................................................................

Assignment Effective Date: ...........................................................................................................................

Principal Amount of Commitment Assigned: ................................................................................................

Percentage of Commitment Assigned¹: ..........................................................................................................

Principal Amount of Loans Assigned: ............................................................................................................

Percentage of Loans Assigned: .......................................................................................................................

Principal Amount of Participations in Letters of Credit: .................................................................................

Percentage of Participations in Letters of Credit: ............................................................................................

The terms set forth above are hereby agreed to:	Accepted2:
[Name of Assignor], as Assignor,	JPMORGAN CHASE BANK, N.A., as Administrative Agent and Issuing Bank,
By:___________________________________ Name: Title:	By:___________________________________ Name: Title:
[Name of Assignee], as Assignee,	EL PASO ELECTRIC COMPANY
By:___________________________________ Name: Title:	By:___________________________________ Name: Title:
	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II
	By:___________________________________ Name: Title:

________________________________

1. Set forth, to at least 8 decimals, as a percentage of the Total Commitment of all Lenders.

2. To be completed to the extent consents are required under Section 10.04(b) of the Credit Agreement.

B-2

EXHIBIT C

[Form of]

BORROWING REQUEST

JPMorgan Chase Bank, N.A., as Administrative Agent

for the Lenders referred to below

1111 Fannin Street, 10th Floor

Houston, TX 77002

Attention of [ ]

Ladies and Gentlemen: [Date]

The undersigned, [EL PASO ELECTRIC COMPANY] [THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II] (the “Borrower”), refers to the Amended and Restated Credit Agreement dated as of November 15, 2011, as amended, supplemented or otherwise modified from time to time (the “Credit Agreement”), among El Paso Electric Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II, the lenders from time to time party thereto (the “Lenders”), JPMorgan Chase Bank, N.A., as issuing bank and as administrative agent for the Lenders, and Union Bank, N.A., as syndication agent. Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement. The Borrower hereby gives you notice pursuant to Section 2.03 of the Credit Agreement that it requests a Borrowing under the Credit Agreement, and in that connection sets forth below the terms on which such Borrowing is requested to be made:

(A) Date of Borrowing (which is a Business Day).....................................................................................

(B) Principal Amount of Borrowing³ .........................................................................................................

(C) Interest rate basis⁴ ...............................................................................................................................

(D) Interest Period and the last day thereof⁵ ..............................................................................................

(E) Funds are requested to be disbursed to the Borrower's account with

[JPMorgan Chase Bank] (Account No. [ ]).

_________________________

3. With respect to any Eurodollar Borrowing, not less than $5,000,000 and in an integral multiple of $1,000,000, and with respect to any ABR Borrowing, not less than $100,000 and in an integral multiple of $1,000, but in any event not exceeding the available Total Commitment available to the Borrowers.

4. Specify Eurodollar Borrowing or ABR Borrowing.

5. Which shall be subject to the definition of “Interest Period” and end not later than the Maturity Date (applicable only for Eurodollar Borrowings only).

C-1

Upon acceptance of any or all of the Loans offered by the Lenders in response to this request, the Borrower shall be deemed to have represented and warranted that the conditions to lending specified in Sections 4.01(b) and (c) of the Credit Agreement have been satisfied.

[APPLICABLE BORROWER],

by: ______________________________

Name:

Title: [Responsible Officer]

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EXHIBIT D

SUBSIDIARY GUARANTEE AGREEMENT (as supplemented from time to time, this “Agreement”) dated as of [ ], between [ ], a [ ] [corporation] (the “Guarantor”) and JPMORGAN CHASE BANK, N.A. (“JPMorgan”), as Administrative Agent (as defined below).

Reference is made to the Amended and Restated Credit Agreement dated as of November 15, 2011 (and as amended, supplemented or otherwise modified from time to time, the “Credit Agreement”), among El Paso Electric Company, a Texas corporation (“El Paso”), The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II (the “Trustee”; each of El Paso and the Trustee is referred to individually herein as a “Borrower” and collectively as the “Borrowers”), the Lenders (as defined in the Credit Agreement), JPMorgan, as issuing bank and as administrative agent (in such capacity, the “Administrative Agent”) for the Lenders, and Union Bank, N.A., as syndication agent. Capitalized terms used herein and not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

Pursuant to Section 5.09 of the Credit Agreement, El Paso has agreed, among other things, to cause any Material Subsidiary to execute a guarantee of all the Obligations (as defined below). The Guarantor is a Material Subsidiary and acknowledges that it will derive substantial benefit from the commitments of the Lenders to make Loans to the Borrowers and the commitment of the Issuing Bank to issue Letters of Credit for the account of the Borrowers. Accordingly, the Guarantor agrees with each Lender, the Issuing Bank, the Syndication Agent and the Administrative Agent (each such person, together with its successors and assigns, a “Guaranteed Party”) as follows:

SECTION 1.Guarantee. The Guarantor unconditionally guarantees, as a primary obligor and not merely as a surety, (a) the due and punctual payment of (i) the principal of and premium, if any, and interest (including interest accruing during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding) on the Loans, when and as due, whether at maturity, by acceleration, upon one or more dates set for prepayment or otherwise, (ii) each payment required to be made by a Borrower under the Credit Agreement in respect of any Letter of Credit, when and as due, including payments in respect of reimbursement of disbursements, interest thereon and obligations to provide cash collateral, and (iii) all other monetary obligations, including fees, costs, expenses and indemnities, whether primary, secondary, direct, contingent, fixed or otherwise (including monetary obligations incurred during the pendency of any bankruptcy, insolvency, receivership or other similar proceeding, regardless of whether allowed or allowable in such proceeding), of the Borrowers to the Guaranteed Parties under the Credit Agreement and the other Loan Documents and (b) the due and punctual performance of all covenants, agreements, obligations and liabilities of the Borrowers under or pursuant to the Credit Agreement and the other Loan Documents (all the monetary and other obligations referred to in the preceding clauses (a) and (b) being collectively called the “Obligations”). The Guarantor further agrees that the Obligations may be extended or renewed, in whole or in part, without

D-1

notice to or further assent from it, and that it will remain bound upon its guarantee notwithstanding any extension or renewal of any Obligation.

SECTION 2.Obligations Not Waived. To the fullest extent permitted by applicable law, the Guarantor waives presentment to, demand of payment from and protest to the Borrowers of any of the Obligations, and also waives notice of acceptance of its guarantee and notice of protest for nonpayment. To the fullest extent permitted by applicable law, the obligations of the Guarantor hereunder shall not be affected by (a) the failure of the Administrative Agent or any other Guaranteed Party to assert any claim or demand or to enforce or exercise any right or remedy against the Borrowers, (b) any rescission, waiver, amendment or modification of, or any release from any of the terms or provisions of the Credit Agreement, any other Loan Document, any Guarantee or any other agreement, including with respect to any other guarantor of the Obligations or (c) any release or substitution of any one or more endorsers, other guarantors or other obligors of all or any portion of the Obligations.

SECTION 3.Guarantee of Payment. The Guarantor further agrees that its guarantee constitutes a guarantee of payment when due and not of collection, and waives any right to require that any resort be had by the Administrative Agent or any other Guaranteed Party to any of the security held for payment of the Obligations or to any balance of any deposit account or credit on the books of the Administrative Agent or any other Guaranteed Party in favor of the Borrowers or any other person.

SECTION 4.No Discharge or Diminishment of Guarantee. The obligations of the Guarantor hereunder shall not be subject to any reduction, limitation, impairment or termination for any reason (other than the payment in full in cash of the Obligations), including any claim of waiver, release, surrender, alteration or compromise of any of the Obligations, and shall not be subject to any defense or setoff, counterclaim, recoupment or termination whatsoever by reason of the invalidity, illegality or unenforceability of the Obligations or otherwise. Without limiting the generality of the foregoing, the obligations of the Guarantor hereunder shall not be discharged or impaired or otherwise affected by the failure of the Administrative Agent or any other Guaranteed Party to assert any claim or demand or to enforce any remedy under the Credit Agreement, any other Loan Document or any other agreement, by any waiver or modification of any provision of any thereof, by any default, failure or delay, willful or otherwise, in the performance of the Obligations, or by any other act or omission that may or might in any manner or to any extent vary the risk of the Guarantor or that would otherwise operate as a discharge of the Guarantor as a matter of law or equity (other than the payment in full in cash of all the Obligations).

SECTION 5.Defenses of Borrowers Waived. To the fullest extent permitted by applicable law, the Guarantor waives any defense based on or arising out of any defense of a Borrower or the unenforceability of the Obligations or any part thereof from any cause, or the cessation from any cause of the liability of a Borrower, other than the payment in full in cash of the Obligations. The Administrative Agent and the other Guaranteed Parties may, at their election, compromise or adjust any part of the Obligations, make any other accommodation with the Borrowers or any other guarantor or exercise any other right or remedy available to them against the Borrowers or any other guarantor, without affecting or impairing in any way the liability of the Guarantor hereunder except to the extent the Obligations have been fully, finally

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paid in cash. To the fullest extent permitted by applicable law, the Guarantor waives any defense arising out of any such election even though such election operates, pursuant to applicable law, to impair or to extinguish any right of reimbursement or subrogation or other right or remedy of Guarantor against a Borrower or any other guarantor, as the case may be.

SECTION 6.Agreement to Pay. In furtherance of the foregoing and not in limitation of any other right that the Administrative Agent or any other Guaranteed Party has at law or in equity against the Guarantor by virtue hereof, upon the failure of a Borrower to pay any Obligation when and as the same shall become due, whether at maturity, by acceleration, after notice of prepayment or otherwise, the Guarantor hereby promises to and will forthwith pay, or cause to be paid, to the Administrative Agent or such other Guaranteed Party as designated thereby in cash the amount of such unpaid Obligations. Upon payment by the Guarantor of any sums to the Administrative Agent or any Guaranteed Party as provided above, all rights of the Guarantor against the Borrowers arising as a result thereof by way of right of subrogation, contribution, reimbursement, indemnity or otherwise shall in all respects be subordinate and junior in right of payment to the prior payment in full in cash of all the Obligations. In addition, any indebtedness of a Borrower now or hereafter held by the Guarantor is hereby subordinated in right of payment to the prior payment in full of the Obligations. If any amount shall erroneously be paid to the Guarantor on account of (i) such subrogation, contribution, reimbursement, indemnity or similar right or (ii) any such indebtedness of a Borrower, such amount shall be held in trust for the benefit of the Guaranteed Parties and shall forthwith be paid to the Administrative Agent to be credited against the payment of the Obligations, whether matured or unmatured, in accordance with the terms of the Loan Documents.

SECTION 7.Information. The Guarantor assumes all responsibility for being and keeping itself informed of each Borrower's financial condition and assets, and of all other circumstances bearing upon the risk of nonpayment of the Obligations and the nature, scope and extent of the risks that the Guarantor assumes and incurs hereunder, and agrees that none of the Administrative Agent or the other Guaranteed Parties will have any duty to advise the Guarantor of information known to it or any of them regarding such circumstances or risks.

SECTION 8.Representations and Warranties. The Guarantor represents and warrants that all representations and warranties relating to it contained in the Credit Agreement are true and correct.

SECTION 9.Termination. The guarantee made hereunder (a) shall terminate when all the Obligations have been indefeasibly paid in full and the Lenders have no further commitment to lend under the Credit Agreement, the L/C Exposure has been reduced to zero and the Issuing Bank has no further obligation to issue Letters of Credit under the Credit Agreement and (b) shall continue to be effective or be reinstated, as the case may be, if at any time payment, or any part thereof, of any Obligation is rescinded or must otherwise be restored by any Guaranteed Party or the Guarantor upon the bankruptcy or reorganization of either Borrower or otherwise.

SECTION 10.Binding Effect; Assignments. Whenever in this Agreement any of the parties hereto is referred to, such reference shall be deemed to include the successors and assigns of such party; and all covenants, promises and agreements by or on behalf of the Guarantor that are contained in this Agreement shall bind and inure to the benefit of each party hereto and their

D-3

respective successors and assigns. This Agreement shall become effective when it shall have been executed on behalf of the Guarantor and the Administrative Agent, and thereafter shall be binding upon the Guarantor and the Administrative Agent and their respective successors and assigns, and shall inure to the benefit of the Guarantor, the Administrative Agent and the other Guaranteed Parties, and their respective successors and assigns, except that the Guarantor shall not have the right to assign its rights or obligations hereunder or any interest herein (and any such attempted assignment shall be void). If all of the capital stock of the Guarantor is sold, transferred or otherwise disposed of (other than to an Affiliate of a Borrower) pursuant to a transaction permitted by the Credit Agreement, the Guarantor shall be released from its obligations under this Agreement without further action.

SECTION 11.Waivers; Amendment. (a) No failure or delay of the Administrative Agent in exercising any power or right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right or power, or any abandonment or discontinuance of steps to enforce such a right or power, preclude any other or further exercise thereof or the exercise of any other right or power. The rights and remedies of the Administrative Agent hereunder and of the other Guaranteed Parties under the other Loan Documents are cumulative and are not exclusive of any rights or remedies that they would otherwise have. No waiver of any provision of this Agreement or consent to any departure by the Guarantor therefrom shall in any event be effective unless the same shall be permitted by paragraph (b) below, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. No notice or demand on the Guarantor in any case shall entitle the Guarantor to any other or further notice or demand in similar or other circumstances.

(b)Neither this Agreement nor any provision hereof may be waived, amended or modified except pursuant to a written agreement entered into between the Guarantor and the Administrative Agent, with the prior written consent of the Required Lenders (except as otherwise provided in the Credit Agreement).

SECTION 12.GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

SECTION 13.Notices. All communications and notices hereunder shall be in writing and given as provided in Section 10.01 of the Credit Agreement. All communications and notices hereunder to the Guarantor shall be given to it at its address set forth below its name on the signature page hereto, with a copy to El Paso.

SECTION 14.Survival of Agreement; Severability. (a) All covenants, agreements, representations and warranties made by the Guarantor herein and in the certificates or other instruments prepared or delivered in connection with or pursuant to this Agreement or any other Loan Document shall be considered to have been relied upon by the Administrative Agent and the other Guaranteed Parties and shall survive the making by the Lenders of Loans and the issuance of the Letters of Credit by the Issuing Bank regardless of any investigation made by the Guaranteed Parties or on their behalf, and shall continue in full force and effect as long as the principal of or any accrued interest on any Loan or any other fee or amount payable by a

D-4

Borrower under the Credit Agreement or any other Loan Document is outstanding and unpaid or the L/C Exposure does not equal zero and as long as the Commitments have not been terminated.

(b)In the event any one or more of the provisions contained in this Agreement or in any other Loan Document should be held invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein and therein shall not in any way be affected or impaired thereby (it being understood that the invalidity of a particular provision in a particular jurisdiction shall not in and of itself affect the validity of such provision in any other jurisdiction). The parties shall endeavor in good-faith negotiations to replace the invalid, illegal or unenforceable provisions with valid provisions the economic effect of which comes as close as possible to that of the invalid, illegal or unenforceable provisions.

SECTION 15.Counterparts. This Agreement may be executed in counterparts, each of which shall constitute an original, but all of which when taken together shall constitute a single contract, and shall become effective as provided in Section 10. Delivery of an executed signature page to this Agreement by facsimile transmission shall be as effective as delivery of a manually executed counterpart of this Agreement.

SECTION 16.Rules of Interpretation. The rules of interpretation specified in Section 1.02 of the Credit Agreement shall be applicable to this Agreement.

SECTION 17.Jurisdiction; Consent to Service of Process. (a) The Guarantor hereby irrevocably and unconditionally submits, for itself and its property, to the exclusive jurisdiction of any New York State court or Federal court of the United States of America sitting in New York City, and any appellate court from any thereof, in any action or proceeding arising out of or relating to this Agreement or the other Loan Documents, or for recognition or enforcement of any judgment, and each of the parties hereto hereby irrevocably and unconditionally agrees that all claims in respect of any such action or proceeding may be heard and determined in such New York State or, to the extent permitted by law, in such Federal court. Each of the parties hereto agrees that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law. Nothing in this Agreement shall affect any right that the Administrative Agent or any other Guaranteed Party may otherwise have to bring any action or proceeding relating to this Agreement or the other Loan Documents against the Guarantor or its properties in the courts of any jurisdiction.

(b)The Guarantor hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection that it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the other Loan Documents in any New York State or Federal court. Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(c)Each party to this Agreement irrevocably consents to service of process in the manner provided for notices in Section 13. Nothing in this Agreement will affect the right of any party to this Agreement to serve process in any other manner permitted by law.

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SECTION 18.WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE OTHER LOAN DOCUMENTS. EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER LOAN DOCUMENTS, AS APPLICABLE, BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION 18.

SECTION 19.Right of Setoff. If an Event of Default shall have occurred and be continuing, each Guaranteed Party is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other Indebtedness at any time owing by such Guaranteed Party to or for the credit or the account of the Guarantor against any or all the obligations of the Guarantor now or hereafter existing under this Agreement and the other Loan Documents held by such Guaranteed Party, irrespective of whether or not such Guaranteed Party shall have made any demand under this Agreement or any other Loan Document and although such obligations may be unmatured. The rights of each Guaranteed Party under this Section 19 are in addition to other rights and remedies (including other rights of setoff) which such Guaranteed Party may have.

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IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written.

[MATERIAL SUBSIDIARY],

by:_________________________________

Name:

Title:

Address for Notices:

JPMORGAN CHASE BANK, N.A.,

as Administrative Agent,

by:__________________________________

Name:

Title:

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EX-12.01

Exhibit 12.01

El Paso Electric Company
Computation of Ratios of Earnings to Fixed Charges
(Dollars in Thousands)
	Years Ended December 31,
	2011			2010			2009			2008			2007
Earnings from Continuing
Operations (a)	$	157,247		$	141,333		$	99,977		$	115,451		$	109,220
Fixed Charges (b)
Interest charges	55,104			51,080			50,908			48,813			37,648
Interest portion of rent expense	908			830			929			1,085			1,181
Total Fixed Charges	56,012			51,910			51,837			49,898			38,829
Capitalized Interest	(18,186		)	(19,974		)	(16,283		)	(15,872		)	(11,897		)
Earnings (c)	$	195,073		$	173,269		$	135,531		$	149,477		$	136,152
Ratio of Earnings to Fixed Charges	3.5			3.3			2.6			3.0			3.5

_______________________

(a) Earnings from continuing operations consist of income from continuing operations before income taxes, extraordinary item and cumulative effects of accounting changes.

(b) Fixed charges consist of all interest on indebtedness, amortization of debt discount and expense and the estimated portion of rental expense that represents an interest factor.

(c) Earnings consist of earnings from continuing operations and fixed charges less AFUDC and capitalized interest.

EX-23.01

EXHIBIT 23.01

Consent of Independent Registered Public Accounting Firm

The Board of Directors

El Paso Electric Company:

We consent to the incorporation by reference in the registration statements (Nos. 333-17971, 333‑82129, and 333-142557) on Form S-8 and (No. 333-178319) on Form S‑3 of El Paso Electric Company of our report dated February 24, 2012, with respect to the consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2011 and 2010, 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, 2011 and the effectiveness of internal control over financial reporting as of December 31, 2011, which report appears in the December 31, 2011 annual report on Form 10-K of El Paso Electric Company.

/s/ KPMG LLP

Houston, Texas

February 24, 2012

113

EX-24.02

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

CERTIFICATE OF RESOLUTION

I, Guillermo Silva, Jr., Corporate Secretary of El Paso Electric Company, a Texas corporation (the “Company”), do hereby certify that attached hereto is a true, correct and complete copy of the resolution authorizing signatures pursuant to a Power of Attorney for the 2011 Form 10-K, duly adopted by the Board of Directors of the Company at a meeting of said Board duly convened and held on January 26, 2012.

IN WITNESS THEREOF, I have hereunto set my hand and have affixed the seal of the Company this 6^th day of February 2012.

/s/ GUILLERMO SILVA, JR.Guillermo Silva, Jr.

Corporate Secretary

(Corporate Seal)

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

RESOLUTION TO THE BOARD OF DIRECTORS

January 26, 2012

RESOLVED, that David W. Stevens, David G. Carpenter and Mary E. Kipp are hereby duly appointed the Company's, and its Officers' and Directors', true and lawful attorneys-in-fact and agents, for their place and stead, in any and all capacities, with full power to act alone, to sign the Company's Annual Report on 2011 Form 10-K, and in any and all amendments thereto, and to file such 2011 Form 10-K and each such amendment, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto each of the said attorneys-in-fact and agents, 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 he 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.

EX-31.01

EXHIBIT 31.01

CERTIFICATIONS

I, David W. Stevens, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Company's internal control over financial reporting that occurred during the Company's most recent fiscal quarter (the Company's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting; and

5. The Company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s

auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Dated: February 24, 2012

EL PASO ELECTRIC COMPANY
By:	/s/ David W. Stevens
	David W. Stevens
	Chief Executive Officer
	(Principal Executive Officer)

I, David G. Carpenter, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this report;

4. The Company’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Company and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c) Evaluated the effectiveness of the Company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the Company's internal control over financial reporting that occurred during the Company's most recent fiscal quarter (the Company's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting; and

5. The Company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Company’s auditors and the audit committee of the Company’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Company’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Company’s internal control over financial reporting.

Dated: February 24, 2012

EL PASO ELECTRIC COMPANY
By:	/s/ David G. Carpenter
	David G. Carpenter
	Senior Vice President and
	Chief Financial Officer
	(Principal Financial Officer)

EX-32.01

EXHIBIT 32.01

February 24, 2012

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2011 (the “Report”) of El Paso Electric Company (the “Company”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 (the “Exchange Act”) and Section 1350 of Chapter 63 of Title 18 of the United States Code.

David W. Stevens and David G. Carpenter, each certifies that, to the best of his knowledge:

1.such Report fully complies with the requirements of Section 13(a) of the Exchange Act; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David W. Stevens

David W. Stevens

Chief Executive Officer

/s/ David G. Carpenter

David G. Carpenter

Senior Vice President and Chief Financial Officer

XML

Financial Instruments And Investments (Tables)

12 Months Ended

Dec. 31, 2011

Financial Instruments And Investments [Abstract]

Company's Decommissioning Trust Funds And Investments In Debt Securities

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,
	2011				2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	206,756	$	193,135	$	192,924
Senior Notes	546,662		700,371		546,610		574,700
RGRT Senior Notes (1)	110,000		116,985		110,000		110,371
RCF (1)	33,379		33,379		4,704		4,704
Total	$	883,176	$	1,057,491	$	854,449	$	882,699

 __________________

(1) Nuclear fuel financing as of December 31, 2011 is funded through the $110.0 million RGRT Senior Notes and $13.4 million under the RCF and $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 quarter reflecting current market rates. Consequently, the carrying value approximates fair value.

Schedule of Available for Sale Securities Continuous Unrealized Loss Position

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, 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 (1):
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	)

 ____________________

(1) Includes approximately 96 securities.

	December 31, 2010
	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	$	2,290	$	(51	)	$	441	$	(27	)	$	2,731	$	(78	)
U.S. Government Bonds	9,583		(124		)	—		—			9,583		(124		)
Municipal Obligations	13,145		(278		)	3,763		(145		)	16,908		(423		)
Corporate Obligations	1,855		(18		)	—		—			1,855		(18		)
Total Debt Securities	26,873		(471		)	4,204		(172		)	31,077		(643		)
Common stock	6,943		(774		)	4,303		(420		)	11,246		(1,194		)
Total Temporarily Impaired Securities	$	33,816	$	(1,245	)	$	8,507	$	(592	)	$	42,323	$	(1,837	)

 ______________________

(2) Includes approximately 96 securities.

Unrecognized Gross Unrealized Gains And the Fair Value

The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands):

	December 31, 2011				December 31, 2010
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	25,077	$	1,220	$	18,472	$	793
U.S. Government Bonds	10,263		972		10,450		183
Municipal Obligations	30,310		1,792		15,633		592
Corporate Obligations	7,641		459		7,223		362
Total Debt Securities	73,291		4,443		51,778		1,930
Common Stock	62,479		15,681		56,770		14,142
Cash and Cash Equivalents	3,739		—		3,007		—
Total	$	139,509	$	20,124	$	111,555	$	16,072

Contractual Year For Maturity Of Available-For-Sale Securities

The contractual year for maturity for these available-for-sale securities as of December 31, 2011 is as follows (in thousands):

	Total		2012		2013 through 2016		2017 through 2021		2022 and Beyond
Municipal Debt Obligations	$	37,316	$	1,009	$	12,892	$	14,252	$	9,163
Corporate Debt Obligations	12,400		1,368		3,630		4,338		3,064
U.S. Government Bonds	12,776		1,316		1,685		6,844		2,931

Unrealized Holding Losses Included In Pre-Tax Income

For the twelve months ended December 31, 2011, 2010, and 2009 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2011			2010			2009
Gross unrealized holding losses included in pre-tax income	$	(2,116	)	$	(263	)	$	(5,594	)

Sale of Securities And The Related Effects On Pre-Tax Income

The proceeds from the sale of these securities during the twelve months ended December 31, 2011, 2010, and 2009 and the related effects on pre-tax income are as follows (in thousands):

	2011			2010			2009
Proceeds from sales of available-for-sale securities	$	82,926		$	61,656		$	79,935
Gross realized gains included in pre-tax income	$	1,479		$	1,030		$	3,614
Gross realized losses included in pre-tax income	(721		)	(889		)	(238		)
Gross unrealized losses included in pre-tax income	(2,116		)	(263		)	(5,594		)
Net losses in pre-tax income	$	(1,358	)	$	(122	)	$	(2,218	)
Net unrealized holding gains included in accumulated other comprehensive income	$	1,570		$	6,665		$	12,816
Net losses reclassified out of accumulated other comprehensive income	1,358			122			2,218
Net gains in other comprehensive income	$	2,928		$	6,787		$	15,034

Trading Securities (and Certain Trading Assets)

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

	2011			2010
Balance at January 1	$	2,909		$	2,510
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)	(220		)	399
Balance at December 31	$	1,120		$	2,909

_____________________

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

Fair Value, Measurement Inputs, Disclosure

The fair value of the Company’s Retirement Plan assets at December 31, 2011 and 2010, 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, 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

Description of Securities	Fair Value as of December 31, 2010		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	$	4,975	$	4,975	$	—	$	—
U.S. Treasury Securities	83,601		83,601		—		—
Guaranteed Investment Contract	550		—		550		—
Common Stock	54,957		54,957		—		—
Mutual Funds	19,501		19,501		—		—
Limited Partnership Interest in Real Estate (a)	7,757		—		—		7,757
Total Plan Investments	$	171,341	$	163,034	$	550	$	7,757

 _____________________

(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 fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2011 and 2010, 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, 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	$	—

Description of Securities	Fair Value as  of December 31, 2010		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	$	2,909	$	—	$	—	$	2,909
Available for sale:
U.S. Government Bonds	$	20,033	$	20,033	$	—	$	—
Federal Agency Mortgage Backed Securities	21,204		—		21,204		—
Municipal Bonds	32,541		—		32,541		—
Corporate Asset Backed Obligations	9,077		—		9,077		—
Subtotal, Debt Securities	82,855		20,033		62,822		—
Common Stock	68,016		68,016		—		—
Cash and Cash Equivalents	3,007		3,007		—		—
Total available for sale	$	153,878	$	91,056	$	62,822	$	—

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Financial Instruments And Investments (Unrecognized Gross Unrealized Gains And The Fair Value) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Financial Instruments and Investments [Line Items]
Fair Value	$ 139,509	$ 111,555
Unrealized Gains	20,124	16,072
Minimum
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available for Sale Securities, Weighted Average Term	3 years
Maximum
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available for Sale Securities, Weighted Average Term	7 years
Collateralized Mortgage Backed Securities
Financial Instruments and Investments [Line Items]
Fair Value	25,077	18,472
Unrealized Gains	1,220	793
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available for Sale Securities, Maturity Term	10 years
U.S. Government Bonds
Financial Instruments and Investments [Line Items]
Fair Value	10,263	10,450
Unrealized Gains	972	183
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale Securities, Debt Securities	12,776
Available-for-sale Securities, Debt Maturities, within One Year, Fair Value	1,316
Available-for-sale Securities, Debt Maturities, after One Through Five Years, Fair Value	1,685
Available-for-sale Securities, Debt Maturities, after Five Through Ten Years, Fair Value	6,844
Available-for-sale Securities, Debt Maturities, after Ten Years, Fair Value	2,931
Municipal Bonds
Financial Instruments and Investments [Line Items]
Fair Value	30,310	15,633
Unrealized Gains	1,792	592
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale Securities, Debt Securities	37,316
Available-for-sale Securities, Debt Maturities, within One Year, Fair Value	1,009
Available-for-sale Securities, Debt Maturities, after One Through Five Years, Fair Value	12,892
Available-for-sale Securities, Debt Maturities, after Five Through Ten Years, Fair Value	14,252
Available-for-sale Securities, Debt Maturities, after Ten Years, Fair Value	9,163
Corporate Debt Securities
Financial Instruments and Investments [Line Items]
Fair Value	7,641	7,223
Unrealized Gains	459	362
Available-for-sale Securities, Debt Maturities, Fair Value [Abstract]
Available-for-sale Securities, Debt Securities	12,400
Available-for-sale Securities, Debt Maturities, within One Year, Fair Value	1,368
Available-for-sale Securities, Debt Maturities, after One Through Five Years, Fair Value	3,630
Available-for-sale Securities, Debt Maturities, after Five Through Ten Years, Fair Value	4,338
Available-for-sale Securities, Debt Maturities, after Ten Years, Fair Value	3,064
Debt Securities
Financial Instruments and Investments [Line Items]
Fair Value	73,291	51,778
Unrealized Gains	4,443	1,930
Equity Securities
Financial Instruments and Investments [Line Items]
Fair Value	62,479	56,770
Unrealized Gains	15,681	14,142
Cash and Cash Equivalents
Financial Instruments and Investments [Line Items]
Fair Value	3,739	3,007
Unrealized Gains	$ 0	$ 0

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Accounting for Asset Retirement Obligations Accounting for Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Accounting For Asset Retirement Obligations [Line Items]
Number of External Trust Funds with Independent Trustee with Legal Restrictions To Settling ARO	6
Decommissioning Fund Investments	$ 167,963	$ 153,878

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Regulation (Revised Fixed Fuel Factor) (Details)	Dec. 31, 2011	Nov. 23, 2010 PUCT Docket No. 38895	Jul. 15, 2011 PUCT Docket Number 39599
Regulation [Line Items]
Increase (Decrease) in Fuel Factor (in percent)	11.00%	(14.70%)	9.40%

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Long-Term Debt and Financing Obligations (Details) (USD $)						0 Months Ended		1 Months Ended																																							0 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Nuclear Fuel Financing	Dec. 31, 2011 Working Capital and General Purpose	Dec. 31, 2011 Revolving Credit Facility	Nov. 14, 2011 Revolving Credit Facility Expiring September 2014	Nov. 15, 2011 Revolving Credit Facility Expiring September 2016	Jun. 29, 2008 Short Term Borrowing	Dec. 31, 2011 Bonds and Notes		Dec. 31, 2010 Bonds and Notes		Dec. 31, 2011 Pollution Control Bonds		Dec. 31, 2010 Pollution Control Bonds		Dec. 31, 2011 Pollution Control Bonds 7.25% 2009 Series A Refunding Bonds, due 2040		Dec. 31, 2010 Pollution Control Bonds 7.25% 2009 Series A Refunding Bonds, due 2040		Dec. 31, 2011 Pollution Control Bonds 4.80% 2005 Series A Refunding Bonds, due 2040		Dec. 31, 2010 Pollution Control Bonds 4.80% 2005 Series A Refunding Bonds, due 2040		Dec. 31, 2011 Pollution Control Bonds 7.25% 2009 Series B Refunding Bonds, due 2040		Dec. 31, 2010 Pollution Control Bonds 7.25% 2009 Series B Refunding Bonds, due 2040		Dec. 31, 2011 Pollution Control Bonds 4.00% 2002 Series A Refunding Bonds, due 2032		Dec. 31, 2010 Pollution Control Bonds 4.00% 2002 Series A Refunding Bonds, due 2032		Dec. 31, 2011 Senior Notes		Dec. 31, 2010 Senior Notes		Dec. 31, 2011 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035		Dec. 31, 2010 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035		May 01, 2005 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035	Dec. 31, 2011 Senior Notes 7.50% Senior Notes, Net of Discount, due 2038		Dec. 31, 2010 Senior Notes 7.50% Senior Notes, Net of Discount, due 2038		Jun. 01, 2008 Senior Notes 7.50% Senior Notes, Net of Discount, due 2038	Aug. 31, 2010 RGRT Senior Notes	Dec. 31, 2011 RGRT Senior Notes		Dec. 31, 2010 RGRT Senior Notes		Aug. 18, 2010 RGRT Senior Notes	Dec. 31, 2011 RGRT Senior Notes 3.67% Senior Notes, Series A, due 2015		Dec. 31, 2010 RGRT Senior Notes 3.67% Senior Notes, Series A, due 2015		Dec. 31, 2011 RGRT Senior Notes 4.47% Senior Notes, Series B, due 2017		Dec. 31, 2010 RGRT Senior Notes 4.47% Senior Notes, Series B, due 2017		Dec. 31, 2011 RGRT Senior Notes 5.04% Senior Notes, Series C, due 2020		Dec. 31, 2010 RGRT Senior Notes 5.04% Senior Notes, Series C, due 2020		Dec. 31, 2011 Financing Obligations Revolving Credit Facility		Dec. 31, 2010 Financing Obligations Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt	$ 883,176,000	$ 854,449,000							$ 849,797,000	[1]	$ 849,745,000	[1]	$ 193,135,000	[2]	$ 193,135,000	[2]	$ 63,500,000	[2]	$ 63,500,000	[2]	$ 59,235,000	[2]	$ 59,235,000	[2]	$ 37,100,000	[2]	$ 37,100,000	[2]	$ 33,300,000	[2]	$ 33,300,000	[2]	$ 546,662,000	[3]	$ 546,610,000	[3]	$ 397,894,000	[3]	$ 397,856,000	[3]		$ 148,768,000	[3]	$ 148,754,000	[3]			$ 110,000,000	[1]	$ 110,000,000	[1]		$ 15,000,000	[1]	$ 15,000,000	[1]	$ 50,000,000	[1]	$ 50,000,000	[1]	$ 45,000,000	[1]	$ 45,000,000	[1]
Long-term Line of Credit					33,379,000																																																												33,379,000	[4]	4,704,000	[4]
Long-term Debt, Current Maturities	(33,300,000)	0
Line of Credit, Current	(33,379,000)	(4,704,000)
Long-term debt	816,497,000	849,745,000
Number of tax exempt bond series													4
Debt Instrument, Interest Rate, Effective Percentage																	7.46%		7.46%		5.32%		5.32%		7.49%		7.49%		5.07%		5.07%						7.12%		7.12%			7.67%		7.67%									3.87%		3.87%		4.62%		4.62%		5.16%		5.16%
Debt Instrument, Interest Rate, Stated Percentage													4.00%				7.25%		7.25%		4.80%		4.80%		7.25%		7.25%		4.00%		4.00%						6.00%		6.00%		6.00%	7.50%		7.50%		7.50%							3.67%		3.67%		4.47%		4.47%		5.04%		5.04%
Debt Instrument, Face Amount																																									400,000,000					150,000,000						110,000,000
Debt Instrument, Unamortized Discount																																									2,300,000	1,300,000
Repayments of Short-term Debt								44,000,000
Redemption Price of Notes Equal to Principal Amount, Percentage																																																				100.00%
Proceeds from Issuance of Long-term Debt																																															109,400,000
Line of Credit Facility, Current Borrowing Capacity						200,000,000	200,000,000
Line of Credit Facility, Maximum Borrowing Capacity							300,000,000
Line of Credit Facility Term						4 years
Line of Credit Facility, Amount Outstanding			$ 13,400,000	$ 20,000,000
Line of Credit Weighted Average Interest Rate					1.50%

[1] RGRT Senior NotesOn 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 2011.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.

[2] Pollution Control Bonds (“PCBs”)The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 4.00% 2002 Series A must be remarketed in August 2012 and is shown as current maturities of long-term debt on the Company's 2011 balance sheet.

[3] Senior NotesThe 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.

[4] Revolving Credit FacilityPrior to November 15, 2011, the Company had available a $200 million credit facility with a four-year term ending September 2014. The credit facility provided for the financing of nuclear fuel, which was accomplished through the RGRT that borrowed under the facility to acquire and process nuclear fuel. The Company was obligated to repay the RGRT’s borrowings with interest. Any amounts not borrowed by the RGRT could have been borrowed by the Company for working capital needs.On November 15, 2011, the Company and RGRT entered into an amended and restated 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. Under the terms of the RCF, the Company and RGRT have available $200 million of credit for a term ending September 23, 2016. The Company may request that the RCF be increased up to a total of $300 million during the term of the RCF, subject to lender approval.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 2011. As of December 31, 2011, the total amount borrowed by RGRT was $13.4 million for nuclear fuel under the RCF, and $20.0 million was 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, 2011.

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Accounting for Asset Retirement Obligations (Changes in Estimated Probabilities Assumptions) (Details)	12 Months Ended
	Dec. 31, 2011
Original ARO Liability [Member]
Accounting For Asset Retirement Obligations [Line Items]
Escalation Rate	3.60%
Credit-Risk Adjusted Discount Rate	9.50%
Incremental ARO Liability [Member]
Accounting For Asset Retirement Obligations [Line Items]
Escalation Rate	3.60%
Credit-Risk Adjusted Discount Rate	6.20%

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Commitments, Contingencies and Uncertainties (Narrative) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended			12 Months Ended
	Jul. 31, 2011 States	Dec. 31, 2011	Sep. 01, 2009 Facilities	Dec. 31, 2011 Gila River Boundary Site	Dec. 31, 2011 Minimum T	Dec. 31, 2011 Maximum MT
Number of states affected by the Clean Air Transport Rule	28
Mercury and Air Toxics Standards Required Compliance Period					4 years	5 years
Number of facilities required to inventory emissions			10,000
Defined increase in GHG emissions, in tons					75,000	100,000
Accrual for environmental loss contingencies		$ 0.3
Site contingency ownership percentage of site				16.29%
Accrued EPA Clean Site Costs		$ 0.1

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Employee Benefits (Target Allocations - Other Postretirment Benefit Plans) (Details) (Other Postretirement Benefit Plans, Defined Benefit)	12 Months Ended
	Dec. 31, 2011
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Equity securities	65.00%
Fixed income	30.00%
Alternative investments	5.00%
Total	100.00%

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Regulation (Narrative) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended			6 Months Ended	9 Months Ended	12 Months Ended			27 Months Ended				0 Months Ended		4 Months Ended		12 Months Ended		12 Months Ended	0 Months Ended		12 Months Ended	0 Months Ended	12 Months Ended		56 Months Ended	12 Months Ended
	Dec. 09, 2011 Decimals	Nov. 22, 2011	Oct. 05, 2011	Jun. 30, 2010	Sep. 30, 2011	Dec. 31, 2011	Sep. 30, 2011	Dec. 31, 2010	Sep. 30, 2011	Nov. 01, 2011	Jul. 02, 2010	Dec. 31, 2008	Sep. 30, 2010 Natural Gas Fired Combustion Turbine Unit mW	Dec. 09, 2011 Solar Power Generation Projects [Member] mW	Oct. 08, 2009 Palo Verde Nuclear Generating Plant	Oct. 08, 2009 New Mexico Jurisdictional Non-Fuel And Purchased Power Base Rate	Dec. 31, 2008 Transmission Agreement Luna Energy Facility	Sep. 30, 2008 Transmission Agreement Luna Energy Facility	Dec. 31, 2011 Renewable Procurement Plan, 2011	Mar. 30, 2011 Maximum	Mar. 30, 2011 Minimum	Dec. 31, 2011 TEP Transmission Agreement, per TEP Claim Maximum Tucson Electric Power Company mW	Dec. 03, 2008 TEP Transmission Agreement, per Judgement Tucson Electric Power Company	Dec. 31, 2008 TEP Transmission Agreement, per Judgement Tucson Electric Power Company Luna Energy Facility	Dec. 31, 2011 TEP Transmission Agreement, per Judgement Maximum Tucson Electric Power Company mW	Sep. 30, 2010 TEP Transmission Agreement, per Settlement Tucson Electric Power Company	Dec. 31, 2011 TEP Transmission Agreement, per Settlement Maximum Tucson Electric Power Company mW	Dec. 31, 2011 Two TEP Transmission Agreements, 2011 Maximum Tucson Electric Power Company mW	Nov. 15, 2011 Revolving Credit Facility Expiring September 2016	Oct. 13, 2011 Revolving Credit Facility Expiring September 2016 NMPRC	Oct. 13, 2011 Revolving Credit Facility Expiring September 2016 FERC	Oct. 13, 2011 Revolving Credit Facility Expiring September 2016 Maximum FERC
Regulation [Line Items]
Annual non-fuel base rate increase											$ 17.15
Customer's percentage of off-system sales margins											90.00%
Retained percentage of off-system sales margins				75.00%							10.00%
Regulatory Noncurrent Asset, Amortization Period								P10Y
Reduction in fixed fuel factor, amount						19.7
Reduction in fixed fuel factor, percent						11.00%
Requested Annual Non-Fuel Base Rate Increase							26.3
Requested Return on Equity							10.60%
Reconcilable Fuel Expense									356.5
Number of Months After The Company Can Seek A Fixed Fuel Factor Revision						4 months
Days Available to City, Determination of Base Rates			185 days
Fuel over and under materiality threshold percentage						4.00%
Energy Efficiency Cost Recovery Factor Recovery					8.3
Military Base Discount Recovery Factor (in percent)						0.936%
Under Recovered Discount Charges						3.9
Electric capacity, MW													87	2.6
Certificate of Convenience and Necessity To Construct Number of Solar Power Gerneration Projects	5
Increase in non-fuel purchased power base rate revenues																5.5
Public Utilities Property Plant and Equipment Estimated Useful life Extension															20 years					60 years	40 years
Imputed Return Rate		2.00%
Percentage Of the Company's Jurisdictional Retail Sales which must be provided with Renewable sources																			10.00%
Line of Credit Facility, Current Borrowing Capacity																													200		200
Line of Credit Facility, Maximum Borrowing Capacity																													300	300	300	300
Return of Refund Related to Dispute																							9.7
Loss contingency reserve																		7.2
Pre-tax charge to earnings																	2.5
Interest paid on refunded balance																								0.9
Transmission capacity, MW																						400			200		170	40
Number of Transmission Capacity Agreements										2
Electrical Transmission Revenue Including Interest																										5.4
Percentage of electrical transmission revenue				25.00%
Electrical Transmission Revenue Shared With Customers				0.7
Counterparty estimate of reimbursement												$ 1.5

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Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2011

Accumulated Other Comprehensive Income (Loss)

Schedule of Accumulated Other Comprehensive Income

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, 2008	$	(6,159	)	$	(9,834	)	$	(13,371	)	$	(29,364	)
Other comprehensive income (loss)	15,034			(49,709		)	317			(34,358		)
Income tax benefit (expense)	(3,007		)	16,957			(115		)	13,835
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	)

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Commitments, Contingencies and Uncertainties (Purchase Allowance For Compliance) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Site Contingency [Line Items]
Purchase allowance for reduction of NOx emissions	$ 62	$ 370

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Supplemental Statements of Cash Flows Disclosures Supplemental Statements of Cash Flows Disclosures (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Statements of Cash Flow Disclosures [Abstract]
Interest on long-term debt and borrowing under the revolving credit facility	$ 48,664	$ 47,783	$ 46,836
Income taxes paid (refund), net	(6,260)	7,343	8,596
Grants of restricted shares of common stock	3,268	2,098	1,592
Issuance of performance shares	628	663	0
Acquisition of treasury stock for options exercised	$ 500	$ 0	$ 0

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Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Deferred tax assets:
Benefit of tax loss carryforwards	$ 21,737	$ 286
Alternative minimum tax credit carryforward	19,863	18,370
Pensions and benefits	87,946	62,821
Asset retirement obligation	20,100	33,904
Deferred fuel	0	7,317
Other	20,524	21,093
Total gross deferred tax assets	170,170	143,791
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(424,319)	(359,838)
Decommissioning	(22,633)	(37,936)
Deferred fuel	(2,493)	0
Other	(6,448)	(6,929)
Total gross deferred tax liabilities	(455,893)	(404,703)
Net accumulated deferred income taxes	$ (285,723)	$ (260,912)

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Employee Benefits (Other Comprehensive Income - Retirement Plans) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	$ 77,678	$ 9,874	$ 48,580
Net loss	6,505	3,374	1,625
Net loss	0	(26,605)	0
Prior service cost	(5,812)	(2,754)	(2,754)
Total expense recognized in other comprehensive income	(76,985)	17,351	(49,709)
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	40,181	12,844	48,531
Net loss	(6,190)	(3,331)	(1,549)
Prior service cost	(21)	(21)	(21)
Total expense recognized in other comprehensive income	33,970	9,492	46,961
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	2,980	1,822	1,892
Net loss	(354)	(218)	(76)
Prior service cost	(94)	(94)	(94)
Total expense recognized in other comprehensive income	$ 2,532	$ 1,510	$ 1,722

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Common Stock (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended				12 Months Ended	0 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	May 02, 2007	Dec. 31, 2011 Stock Options	Jan. 26, 2012 Dividend Declared [Member]
Common Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 1				$ 1				$ 1	$ 1
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized												1,000,000
Share Based Compensation Arrangement By Share Based Payment Award, Term													10 years
Dividends, Common Stock, Cash	$ 8.8								$ 27.2
Common Stock, Dividends, Per Share, Declared	$ 0.22	$ 0.22	$ 0.22	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.00	$ 0.66	$ 0.00	$ 0.00			$ 0.22

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Financial Instruments and Investments Financial Instruments and Investments (Carrying Amount and Fair Value Amounts) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011		Dec. 31, 2010
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	$ 1,057,491		$ 882,699
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	883,176		854,449
Pollution Control Bonds | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	206,756		192,924
Pollution Control Bonds | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	193,135		193,135
Senior Notes | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	700,371		574,700
Senior Notes | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	546,662		546,610
RGRT Senior Notes | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	116,985	[1]	110,371	[1]
RGRT Senior Notes | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	110,000	[1]	110,000	[1]
Revolving Credit Facility | Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	33,379	[1]	4,704	[1]
Revolving Credit Facility | Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Fair Value Disclosure	$ 33,379	[1]	$ 4,704	[1]

[1] Nuclear fuel financing as of December 31, 2011 is funded through the $110.0 million RGRT Senior Notes and $13.4 million under the RCF and $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 quarter reflecting current market rates. Consequently, the carrying value approximates fair value.

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Income Taxes (Unrecognized Tax Benefits) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of period	$ 7,300	$ 600	$ 500
Additions/(reductions) based on tax positions related to the current year	2,200	6,300	0
Additions for tax positions of prior years	0	400	400
Reductions for tax positions of prior years	0	0	(300)
Balance at end of period	9,500	7,300	600
Unrecognized tax benefits that would impact effective tax rate	1,100
Unrecognized tax benefit, income tax expense			100
Unrecognized tax benefits, interest on income taxes expense / (benefits)	200	(100)	(200)
Unrecognized tax benefits, income tax penalties and interest accrued	$ 400	$ 200

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Employee Benefits (Amounts Recognized in Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	$ 129,820	$ 95,828
Prior service cost	24	46
Total	129,844	95,874
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	8,990	6,364
Prior service cost	408	502
Total	$ 9,398	$ 6,866

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Commitments, Contingencies and Uncertainties (Future Minimum Payments For Operating Leases) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 1,100,000
2012	1,030,000
2013	951,000
2014	919,000
2015	477,000
2016	$ 438,000
Operating Lease Renewal Option, Term	25 years

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Employee Benefits (Weighted-Average Actuarial Assumptions for Benefit Obligations - Retirement Plans) (Details)	12 Months Ended
	Dec. 31, 2011 Retirement Plans	Dec. 31, 2011 Retirement Income Plan Benefit Obligations	Dec. 31, 2010 Retirement Income Plan Benefit Obligations	Dec. 31, 2011 Supplement Retirement Plan Benefit Obligations	Dec. 31, 2010 Supplement Retirement Plan Benefit Obligations	Dec. 31, 2011 Excess Benefit Plan Benefit Obligations	Dec. 31, 2010 Excess Benefit Plan Benefit Obligations
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate		4.30%	5.40%	3.60%	4.60%	4.10%	5.30%
Rate of compensation increase		5.00%	5.00%			5.00%	5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Discount Rate	1.00%
Defined Benefit Plan, Decrease in Projected Benefit Obiligation, Percentage	12.70%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Discount Rate	1.00%
Defined Benefit Plan, Increase in Projected Benefit Obiligation, Percentage	15.80%

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Commitments, Contingencies and Uncertainties (Power Purchase and Sale Agreement) (Details)	12 Months Ended
	Dec. 31, 2011 mW
Freeport | December 2008 through December 2013
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	125
Freeport | January 2014 through December 2021
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	100
Shell | January 2011 through September 2014
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	40
NRG
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	P20Y
NRG | August 2011 through July 2031
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	20
Sun Edison 1 | 25 years after operational start date
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	12
Sun Edison 2 | 25 years after operational start date
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	10
NextEra Energy Resources
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	P25Y
NextEra Energy Resources | July 2011 through June 2036
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Minimum Quantity Required	5
Sun Edison 1 and Sun Edison 2
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	P25Y

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Long-Term Debt and Financing Obligations Long-term Debt Maturities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Year one	$ 33,300
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	15,000
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Working Capital and General Purpose | Revolving Credit Facility
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Year one	$ 33,400

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Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Selected Quarterly Financial Data

Quarterly Financial Information

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.

	2011 Quarters								2010 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	191,663	$	307,633	$	242,605	$	176,112	$	181,344	$	280,342	$	211,397	$	204,168
Operating income	15,994		102,215		58,121		14,473		13,784		84,098		40,477		30,603
Income before extraordinary gain	5,453		58,321		32,990		6,775		7,466		49,896		21,507		11,449
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		10,286		—		—
Net income	5,453		58,321		32,990		6,775		7,466		60,182		21,507		11,449
Basic earnings per share:
Income before extraordinary gain	0.14		1.41		0.78		0.16		0.18		1.16		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.14		1.41		0.78		0.16		0.18		1.40		0.49		0.26
Diluted earnings per share:
Income before extraordinary gain	0.13		1.40		0.78		0.16		0.17		1.15		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.13		1.40		0.78		0.16		0.17		1.39		0.49		0.26
Dividends declared per share of common stock	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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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Depreciable Assets By Each Major Class) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	$ 2,789,773	$ 2,522,862
Accumulated Depreciation	(1,121,653)	(1,047,498)
Net utility plant	1,947,065	1,865,753
Net plant in service	1,668,120	1,475,364
Nuclear production
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	768,284
Accumulated Depreciation	(240,862)
Net utility plant	527,422
Steam and other
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	557,286
Accumulated Depreciation	(223,109)
Net utility plant	334,177
Total production
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	1,325,570
Accumulated Depreciation	(463,971)
Net utility plant	861,599
Transmission
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	394,385
Accumulated Depreciation	(238,940)
Net utility plant	155,445
Distribution
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	864,746
Accumulated Depreciation	(308,644)
Net utility plant	556,102
General
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	141,921
Accumulated Depreciation	(78,323)
Net utility plant	63,598
Intangible
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Gross Plant	63,151
Accumulated Depreciation	(31,775)
Net utility plant	$ 31,376

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Summary of Significant Accounting Policies (Extraordinary item) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended			3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Sep. 30, 2010 Company's 6 Percent Senior Notes
Debt Instrument [Line Items]
Extraordinary gain, net of income tax expense	$ 0	$ 10,286	$ 0	$ 10,300
Income tax expense related to extraordinary gain	$ 0	$ (5,769)	$ 0	$ 5,800
Debt interest rate				6.00%
Debt Instrument Maturity Year				2035

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Income Taxes (Income Tax Provisions) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Tax Examination [Line Items]
Federal statutory tax rate	35.00%	35.00%	35.00%
Federal income tax expense computed on income at statutory rate	$ 55,036	$ 55,086	$ 34,992
Difference due to:
State taxes, net of federal benefit	1,308	4,066	2,360
AEFUDC	(2,295)	(3,578)	(3,051)
Permanent tax differences	(303)	(3,103)	(618)
Patient Protection and Affordable Care Act	0	4,787	0
Other	(38)	(473)	(639)
Total income tax expense	53,708	56,785	33,044
Tax expense classified as extraordinary gain	0	(5,769)	0
Total income tax expense before extraordinary item	$ 53,708	$ 51,016	$ 33,044
Effective income tax rate	34.20%	36.10%	33.10%
Without Ppaca
Difference due to:
Effective income tax rate	34.20%	33.00%	33.10%

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Employee Benefits (Changes in Funded Status of Plan - Other Postretirment Benefit Plans) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Other Postretirement Benefit Plans, Defined Benefit
Change in projected benefit obligation:
Benefit obligation at end of prior year	$ 95,254		$ 118,267
Service cost	2,988		3,558		3,395
Interest cost	5,379		6,664		6,492
Actuarial loss	32,694		(3,807)
Amendments	0	[1]	(26,605)	[1]
Benefits paid	(4,180)		(3,598)
Retiree contributions	941		584
Medicare Part D subsidy	196		191
Benefit obligation at end of year	133,272		95,254		118,267
Change in plan assets:
Fair value of plan assets at end of prior year	33,660		29,348
Actual return on plan assets	0		2,514
Employer contribution	2,200		4,621
Benefits paid	(4,180)		(3,598)
Retiree contributions	941		584
Medicare Part D subsidy	196		191
Fair value of plan assets at end of year	32,817		33,660		29,348
Funded status	$ (100,455)	[2]	$ (61,594)	[2]

[1] The amendments that occurred during the twelve months ended December 31, 2010 primarily related to modifications to the required copayment levels, deductibles and out-of-pocket maximum responsibilities retained by the retired employees.

[2] These amounts are recognized in the Company’s consolidated balance sheets as a non-current liability.

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Employee Benefits Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Benefit Costs

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

	Years Ended December 31,
	2011					2010					2009
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	6,590		$	260	$	5,888		$	176	$	5,414		$	120
Interest cost	12,871			1,116		12,507			1,122		11,942			1,241
Amendments	—			—		—			838		—			—
Expected return on plan assets	(14,095		)	—		(13,867		)	—		(15,439		)	—
Amortization of:
Net loss	6,190			354		3,331			218		1,549			76
Prior service cost	21			94		21			94		21			94
Net periodic benefit cost	$	11,577		$	1,824	$	7,880		$	2,448	$	3,487		$	1,531

Fair Value, Measurement Inputs, Disclosure

The fair value of the Company’s Retirement Plan assets at December 31, 2011 and 2010, 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, 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

Description of Securities	Fair Value as of December 31, 2010		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	$	4,975	$	4,975	$	—	$	—
U.S. Treasury Securities	83,601		83,601		—		—
Guaranteed Investment Contract	550		—		550		—
Common Stock	54,957		54,957		—		—
Mutual Funds	19,501		19,501		—		—
Limited Partnership Interest in Real Estate (a)	7,757		—		—		7,757
Total Plan Investments	$	171,341	$	163,034	$	550	$	7,757

 _____________________

(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 fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2011 and 2010, 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, 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	$	—

Description of Securities	Fair Value as  of December 31, 2010		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	$	2,909	$	—	$	—	$	2,909
Available for sale:
U.S. Government Bonds	$	20,033	$	20,033	$	—	$	—
Federal Agency Mortgage Backed Securities	21,204		—		21,204		—
Municipal Bonds	32,541		—		32,541		—
Corporate Asset Backed Obligations	9,077		—		9,077		—
Subtotal, Debt Securities	82,855		20,033		62,822		—
Common Stock	68,016		68,016		—		—
Cash and Cash Equivalents	3,007		3,007		—		—
Total available for sale	$	153,878	$	91,056	$	62,822	$	—

Changes in Fair Value of Investments in Real Estate

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, 2009	$	8,288
Unrealized loss in fair value	(531		)
Balance at December 31, 2010	7,757
Sale of land	(102		)
Unrealized gain in fair value	856
Balance at December 31, 2011	$	8,511

Schedule of Accumulated Other Comprehensive Income (Loss)

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, 2008	$	(6,159	)	$	(9,834	)	$	(13,371	)	$	(29,364	)
Other comprehensive income (loss)	15,034			(49,709		)	317			(34,358		)
Income tax benefit (expense)	(3,007		)	16,957			(115		)	13,835
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	)

Retirement Plans

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status

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

	December 31,
	2011						2010
	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	$	242,718		$	24,008		$	215,944		$	21,767
Service cost	6,590			260			5,888			176
Interest cost	12,871			1,116			12,507			1,122
Amendments	—			—			—			838
Actuarial loss	42,508			2,980			16,008			1,822
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Benefit obligation at end of year	296,293			26,547			242,718			24,008
Change in plan assets:
Fair value of plan assets at end of prior year	171,341			—			155,140			—
Actual return on plan assets	16,422			—			17,030			—
Employer contribution	12,000			1,817			6,800			1,717
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Fair value of plan assets at end of year	191,369			—			171,341			—
Funded status at end of year	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

Schedule of Amounts Recognized in Balance Sheet

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(1,844	)	$	—		$	(1,914	)
Noncurrent liabilities	(104,924		)	(24,703		)	(71,377		)	(22,094		)
Total	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(296,293	)	$	(26,547	)	$	(242,718	)	$	(24,008	)
Accumulated benefit obligation	(250,753		)	(26,547		)	(205,167		)	(23,538		)
Fair value of plan assets	191,369			—			171,341			—

Schedule of Amounts Recognized in Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2011				2010
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	129,820	$	8,990	$	95,828	$	6,364
Prior service cost	24		408		46		502
Total	$	129,844	$	9,398	$	95,874	$	6,866

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2011						2010						2009
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	40,181		$	2,980		$	12,844		$	1,822		$	48,531		$	1,892
Amortization of:
Net loss	(6,190		)	(354		)	(3,331		)	(218		)	(1,549		)	(76		)
Prior service cost	(21		)	(94		)	(21		)	(94		)	(21		)	(94		)
Total expense recognized in other comprehensive income	$	33,970		$	2,532		$	9,492		$	1,510		$	46,961		$	1,722

Schedule of Recognized Net Periodic Benefit Obligation and Other Comprehensive Income

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

	Years Ended December 31,
	2011				2010				2009
	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	$	45,547	$	4,356	$	17,372	$	3,958	$	50,448	$	3,253

Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2012 (in thousands):

	Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	11,300	$	560
Prior service cost	20		90

Schedule of Allocation of Plan Assets

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, 2011
Equity securities	50	%
Fixed income	45	%
Alternative investments	5	%
Total	100	%

Schedule of Expected Benefit Payments

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
2012	$	9,132	$	1,844
2013	9,967		1,813
2014	10,932		1,777
2015	11,924		1,758
2016	13,021		1,801
2017-2021	83,027		9,430

Retirement Plans | Net Periodic Benefit Costs

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	2011						2010						2009
			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	5.4	%	4.6	%	5.3	%	5.9	%	5.2	%	6.0	%	6.1	%	6.3	%	6.3	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		8.5	%	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	%

Retirement Plans | Benefit Obligations

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	December 31,
	2011						2010
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.3	%	3.6	%	4.1	%	5.4	%	4.6	%	5.3	%
Rate of compensation increase	5.0	%	N/A		5.0	%	5.0	%	N/A		5.0	%

Other Postretirement Benefit Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Schedule of Net Funded Status

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,
	2011			2010
Change in benefit obligation:
Benefit obligation at end of prior year	$	95,254		$	118,267
Service cost	2,988			3,558
Interest cost	5,379			6,664
Actuarial loss	32,694			(3,807		)
Amendments (a)	—			(26,605		)
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Benefit obligation at end of year	133,272			95,254
Change in plan assets:
Fair value of plan assets at end of prior year	33,660			29,348
Actual return on plan assets	—			2,514
Employer contribution	2,200			4,621
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Fair value of plan assets at end of year	32,817			33,660
Funded status (b)	$	(100,455	)	$	(61,594	)

_____________________

(a) The amendments that occurred during the twelve months ended December 31, 2010 primarily related to modifications to the required copayment levels, deductibles and out-of-pocket maximum responsibilities retained by the retired employees.

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

Schedule of Net Benefit Costs

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

	Years Ended December 31,
	2011			2010			2009
Service cost	$	2,988		$	3,558		$	3,395
Interest cost	5,379			6,664			6,492
Expected return on plan assets	(1,823		)	(1,529		)	(1,499		)
Amortization of:
Prior service benefit	(5,927		)	(2,869		)	(2,869		)
Net gain	(39		)	(175		)	—
Net periodic benefit cost	$	578		$	5,649		$	5,519

Schedule of Defined Benefit Plan Amounts Recognized in Other Comprehensive Income (Loss)

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

	Years Ended December 31,
	2011		2010			2009
Net loss (gain)	$	34,517	$	(4,792	)	$	(1,843	)
Prior service benefit	—		(26,605		)	—
Amortization of:
Prior service benefit	5,927		2,869			2,869
Net gain	39		175			—
Total recognized in other comprehensive income	$	40,483	$	(28,353	)	$	1,026

Schedule of Recognized Net Periodic Benefit Obligation and Other Comprehensive Income

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

	Years Ended December 31,
	2011		2010			2009
Total recognized in net periodic benefit cost and other comprehensive income	$	41,061	$	(22,704	)	$	6,545

Schedule of Allocation of Plan Assets

The Company’s target allocations for the plan’s assets are presented below:

	December 31, 2011
Equity securities	65	%
Fixed income	30	%
Alternative investments	5	%
Total	100	%

Fair Value, Measurement Inputs, Disclosure

The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2011 and 2010, 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, 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
Description of Securities	Fair Value as of December 31, 2010		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	$	4,122	$	4,122	$	—	$	—
Municipal Securities – Tax Exempt	11,348		—		11,348		—
Common Stock	16,735		16,735		—		—
Limited Partnership Interest in Real Estate (a)	1,455		—		—		1,455
Total Plan Investments	$	33,660	$	20,857	$	11,348	$	1,455

 ___________________

(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.

Changes in Fair Value of Investments in Real Estate

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, 2009	$	1,554
Unrealized loss in fair value	(99		)
Balance at December 31, 2010	1,455
Sale of land	(19		)
Unrealized gain in fair value	160
Balance at December 31, 2011	$	1,596

Schedule of Expected Benefit Payments

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

2012	$	3,519
2013	4,006
2014	4,507
2015	5,058
2016	5,614
2017-2021	35,367

Schedule of Accumulated Other Comprehensive Income (Loss)

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,
	2011			2010
Net loss (gain)	$	20,144		$	(14,411	)
Prior service credit	(30,647		)	(36,574		)
	$	(10,503	)	$	(50,985	)

Other Postretirement Benefit Plans, Defined Benefit | Net Periodic Benefit Costs

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	2011		2010		2009
Discount rate at beginning of year	5.5	%	5.9	%	6.0	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.9	%
Health care cost trend rates:
Initial	8.5	%	8.5	%	9.0	%
Ultimate	5.0	%	5.0	%	5.0	%
Year ultimate reached	2018		2017		2017

Other Postretirement Benefit Plans, Defined Benefit | Accrued Postretirement Benefit

Defined Benefit Plan Disclosure [Line Items]

Schedule of Assumptions Used

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

	December 31,
	2011		2010
Discount rate at end of year	4.3	%	5.5	%
Health care cost trend rates:
Initial	8.0	%	8.5	%
Ultimate	5.0	%	5.0	%
Year ultimate reached	2026		2018

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Summary of Jointly Owned Utility Plants) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Palo Verde
Jointly Owned Utility Plant Interests [Line Items]
Electric plant in service	$ 768,284	$ 772,710
Accumulated depreciation	(240,862)	(225,461)
Construction work in progress	53,822	48,703
Total	581,244	595,952
Other Jointly Owned Utlity Plant
Jointly Owned Utility Plant Interests [Line Items]
Electric plant in service	211,983	209,427
Accumulated depreciation	(164,622)	(159,679)
Construction work in progress	1,634	1,940
Total	$ 48,995	$ 51,688

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Common Stock (Basic and Diluted Earnings Per Share) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Common Stock [Abstract]
Basic number of common shares outstanding									41,349,883	43,129,735	44,524,146
Dilutive effect of unvested performance awards									206,658	101,780	27,876
Dilutive effect of stock options									30,518	62,904	43,045
Diluted number of common shares outstanding									41,587,059	43,294,419	44,595,067
Net income	$ 5,453	$ 58,321	$ 32,990	$ 6,775	$ 7,466	$ 60,182	$ 21,507	$ 11,449	$ 103,539	$ 100,603	$ 66,933
Income allocated to participating restricted stock									(471)	(403)	(240)
Net income available to common shareholders basic									103,068	100,200	66,693
Income reallocated to participating restricted stock									(469)	(401)	(240)
Net income available to common shareholders diluted									$ 103,070	$ 100,202	$ 66,693
Earnings Per Share, Basic, Distributed									$ 0.66	$ 0.00	$ 0.00
Earnings Per Share, Basic, Undistributed									$ 1.83	$ 2.32	$ 1.50
Basic net income per common share	$ 0.14	$ 1.41	$ 0.78	$ 0.16	$ 0.18	$ 1.40	$ 0.49	$ 0.26	$ 2.49	$ 2.32	$ 1.50
Earnings Per Share, Diluted, Distributed									$ 0.66	$ 0.00	$ 0.00
Earnings Per Share, Diluted, Undistributed									$ 1.82	$ 2.31	$ 1.50
Diluted net income per common share	$ 0.13	$ 1.40	$ 0.78	$ 0.16	$ 0.17	$ 1.39	$ 0.49	$ 0.26	$ 2.48	$ 2.31	$ 1.50

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Financial Instruments And Investments (Marketable Securities Fair Value And Unrealized Losses) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 securities		Dec. 31, 2010 securities
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	$ 17,103	[1]	$ 33,816	[1]
Fair Value, 12 Months or Longer	11,351	[1]	8,507	[1]
Fair Value, Total	28,454	[1]	42,323	[1]
Unrealized Losses, Less than 12 Months	(2,223)	[1]	(1,245)	[1]
Unrealized Losses, 12 Months or Longer	(737)	[1]	(592)	[1]
Unrealized Losses, Total	(2,960)	[1]	(1,837)	[1]
Number of securities	96		96
Collateralized Mortgage Backed Securities
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	515	[1]	2,290	[1]
Fair Value, 12 Months or Longer	1,233	[1]	441	[1]
Fair Value, Total	1,748	[1]	2,731	[1]
Unrealized Losses, Less than 12 Months	(8)	[1]	(51)	[1]
Unrealized Losses, 12 Months or Longer	(23)	[1]	(27)	[1]
Unrealized Losses, Total	(31)	[1]	(78)	[1]
U.S. Government Bonds
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	100	[1]	9,583	[1]
Fair Value, 12 Months or Longer	2,413	[1]	0	[1]
Fair Value, Total	2,513	[1]	9,583	[1]
Unrealized Losses, Less than 12 Months	(1)	[1]	(124)	[1]
Unrealized Losses, 12 Months or Longer	(38)	[1]	0	[1]
Unrealized Losses, Total	(39)	[1]	(124)	[1]
Municipal Bonds
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	2,275	[1]	13,145	[1]
Fair Value, 12 Months or Longer	4,731	[1]	3,763	[1]
Fair Value, Total	7,006	[1]	16,908	[1]
Unrealized Losses, Less than 12 Months	(31)	[1]	(278)	[1]
Unrealized Losses, 12 Months or Longer	(144)	[1]	(145)	[1]
Unrealized Losses, Total	(175)	[1]	(423)	[1]
Corporate Debt Securities
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	3,525	[1]	1,855	[1]
Fair Value, 12 Months or Longer	1,234	[1]	0	[1]
Fair Value, Total	4,759	[1]	1,855	[1]
Unrealized Losses, Less than 12 Months	(118)	[1]	(18)	[1]
Unrealized Losses, 12 Months or Longer	(43)	[1]	0	[1]
Unrealized Losses, Total	(161)	[1]	(18)	[1]
Debt Securities
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	6,415	[1]	26,873	[1]
Fair Value, 12 Months or Longer	9,611	[1]	4,204	[1]
Fair Value, Total	16,026	[1]	31,077	[1]
Unrealized Losses, Less than 12 Months	(158)	[1]	(471)	[1]
Unrealized Losses, 12 Months or Longer	(248)	[1]	(172)	[1]
Unrealized Losses, Total	(406)	[1]	(643)	[1]
Equity Securities
Financial Instruments and Investments [Line Items]
Fair Value, Less than 12 Months	10,688	[1]	6,943	[1]
Fair Value, 12 Months or Longer	1,740	[1]	4,303	[1]
Fair Value, Total	12,428	[1]	11,246	[1]
Unrealized Losses, Less than 12 Months	(2,065)	[1]	(774)	[1]
Unrealized Losses, 12 Months or Longer	(489)	[1]	(420)	[1]
Unrealized Losses, Total	$ (2,554)	[1]	$ (1,194)	[1]

[1] Includes approximately 96 securities.

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Common Stock (Schedule of Unvested Restricted Stock) (Details) (Restricted Stock, USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years		Dec. 31, 2010	Dec. 31, 2009
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested [Roll Forward]
Share based compensation, outstanding at beginning of period (in shares)	143,371
Total restricted stock awards (in shares)	118,110
Total lapsed restrictions and vesting (in shares)	(103,096)
Total forfeitures (in shares)	(2,200)
Share based compensation, outstanding at end of period (in shares)	156,185		143,371
Performance shares outstanding, Weighted Average Grant Date Fair Value, Beginning of Period	$ 18.30
Weighted average fair value per share	$ 28.98		$ 20.03	$ 14.59
Weighted average fair value lapsed restrictions and vesting	$ 17.45
Weighted average fair value forfeitures	$ 23.20
Performance shares outstanding, Weighted Average Grant Date Fair Value, End of Period	$ 26.87		$ 18.30
Unrecognized compensation expense expected to be recognized for the weighted average contractual term of the restricted shares outstanding at end of period	$ 2,136	[1]
Aggregated intrinsic value for restricted stock oustanding at end of period	$ 5,410
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2

[1] The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately two years.

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Regulation (Refund Fuel Cost Over Recoveries) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 17, 2009 PUCT Docket No. 37788	May 12, 2010 PUCT Docket No. 38253	Oct. 20, 2010 PUCT Docket No. 38802	Feb. 18, 2011 PUCT Docket No. 39159
Regulation [Line Items]
Refund Amount	$ 11,800	$ 11,100	$ 12,800	$ 11,800

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Significant Accounting Policies

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 regulartory 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 2011, 2010 and 2009 was 2.80%, 3.21%, and 3.22%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note E.

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

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 rate used in 2011 was 8.54% . The AFUDC rate utilized for the first six months of 2010 was 9.01% and 8.47% thereafter. The AFUDC rate utilized in 2009 was 8.94%.

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 income (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 an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $19.6 million and $16.6 million at December 31, 2011 and 2010, 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 2011, 2010 and 2009 are as follows (in thousands):

	2011		2010		2009
Balance at beginning of year	$	2,885	$	1,191	$	3,123
Additions:
Charged to costs and expense	6,209		4,756		3,289
Recovery of previous write-offs	2,034		852		1,316
Uncollectible receivables written off	8,113		3,914		6,537
Balance at end of year	$	3,015	$	2,885	$	1,191

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. 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. For a full discussion of the Company’s accounting policies for its employee benefits. See Note M.

Reclassification. Certain amounts in the consolidated financial statements for 2010 and 2009 have been reclassified to conform with the 2011 presentation.

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Financial Instruments and Investments Financial Instruments and Investments (Reconciliation) (Details) (Debt Securities, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Debt Securities
Fair Value in Investment in Debt Securities [Roll Forward]
Balance at January 1	$ 2,909	$ 2,510
Sale of debt security	(2,000)	0
Realized gain on sale of debt security	431	0
Net unrealized gains (losses) in fair value recognized in income on debt securities still held	(220)	399
Balance at December 31	$ 1,120	$ 2,909

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Common Stock (Weighted Average Fair Value Per Share) (Details) (Restricted Stock, USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value per share	$ 28.98	$ 20.03	$ 14.59

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Summary of Significant Accounting Policies (Utility Plant) (Details)	6 Months Ended		12 Months Ended
	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Significant Accounting Policies [Line Items]
Average composite depreciation rate			2.80%	3.21%	3.22%
AFUDC rate	8.47%	9.01%	8.54%		8.94%
Minimum
Significant Accounting Policies [Line Items]
PP&E average useful life			3
Maximum
Significant Accounting Policies [Line Items]
PP&E average useful life			48

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Regulatory Assets and Liabilities Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities [Abstract]

Schedule of Regulatory Assets

Regulatory assets and liabilities reflected in the Company's consolidated balance sheets are presented below (in thousands):

	Amortization Period Ends	December 31, 2011		December 31, 2010
Regulatory assets
Regulatory tax assets (a)	(b)	$	52,281	$	37,230
Loss on reacquired debt (c)	May 2035	20,044		20,897
Final coal reclamation (a)	July 2016	6,655		10,282
Nuclear fuel postload daily financing charge	(d)	3,470		2,007
Unrecovered issuance costs due to reissuance of PCBs (c)	April 2040	578		599
Texas energy efficiency	(e)	4,497		5,460
Texas 2009 rate case costs (f)	June 2012	1,146		3,298
Texas 2012 rate case costs	(g)	648		—
Texas military base discount and recovery factor	(h)	2,526		761
New Mexico 2009 rate case procurement plan costs (f)	December 2011	—		232
New Mexico procurement plan costs	(g)	139		122
New Mexico 2009 rate case renewable energy credits (f)	December 2011	—		1,139
New Mexico renewable energy credits	(g)	2,884		930
New Mexico 2009 rate case costs (f)	December 2012	253		506
New Mexico 2010 FPPCAC audit	(g)	427		—
New Mexico Palo Verde deferred depreciation	(b)	5,176		4,773
New Mexico energy efficiency	(e)	303		321
Total regulatory assets		$	101,027	$	88,557
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	16,138	$	9,326
Accumulated deferred investment tax credit (i)	(b)	4,911		5,163
Total regulatory liabilities		$	21,049	$	14,489

________________

(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 30 years beginning in 2005.

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

(e) This asset is recovered 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.

(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.

Schedule of Regulatory Liabilities

Regulatory assets and liabilities reflected in the Company's consolidated balance sheets are presented below (in thousands):

	Amortization Period Ends	December 31, 2011		December 31, 2010
Regulatory assets
Regulatory tax assets (a)	(b)	$	52,281	$	37,230
Loss on reacquired debt (c)	May 2035	20,044		20,897
Final coal reclamation (a)	July 2016	6,655		10,282
Nuclear fuel postload daily financing charge	(d)	3,470		2,007
Unrecovered issuance costs due to reissuance of PCBs (c)	April 2040	578		599
Texas energy efficiency	(e)	4,497		5,460
Texas 2009 rate case costs (f)	June 2012	1,146		3,298
Texas 2012 rate case costs	(g)	648		—
Texas military base discount and recovery factor	(h)	2,526		761
New Mexico 2009 rate case procurement plan costs (f)	December 2011	—		232
New Mexico procurement plan costs	(g)	139		122
New Mexico 2009 rate case renewable energy credits (f)	December 2011	—		1,139
New Mexico renewable energy credits	(g)	2,884		930
New Mexico 2009 rate case costs (f)	December 2012	253		506
New Mexico 2010 FPPCAC audit	(g)	427		—
New Mexico Palo Verde deferred depreciation	(b)	5,176		4,773
New Mexico energy efficiency	(e)	303		321
Total regulatory assets		$	101,027	$	88,557
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	16,138	$	9,326
Accumulated deferred investment tax credit (i)	(b)	4,911		5,163
Total regulatory liabilities		$	21,049	$	14,489

________________

(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 30 years beginning in 2005.

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

(e) This asset is recovered 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.

(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.

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Regulation (Tables)

12 Months Ended

Dec. 31, 2011

Public Utilities, General Disclosures [Abstract]

Refund Fuel Cost Over Recoveries

The fuel cost over-recovery periods represent the months in which the over-recoveries took place and the refund periods represent the billing month(s) in which customers received the refund amounts shown, including interest:

Docket No.	Date Filed	Date Approved	Recovery Period	Refund Period	Refund Amount (In thousands)
37788	December 17, 2009	February 11, 2010	September – November 2009	February 2010	$	11,800
38253	May 12, 2010	July 15, 2010	December 2009 – March 2010	July – August 2010	11,100
38802	October 20, 2010	December 16, 2010	April – September 2010	December 2010	12,800
39159	February 18, 2011	May 3, 2011	October – December 2010	April 2011	11,800

Revised Fixed Fuel Factor

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

Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor		Effective Billing Month
38895	November 23, 2010	January 6, 2011	(14.7	)%	January 2011
39599	July 15, 2011	August 30, 2011	9.4	%	August 2011

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Employee Benefits (Net Periodic Benefit Cost) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 2,988	$ 3,558	$ 3,395
Interest cost	5,379	6,664	6,492
Expected return on plan assets	(1,823)	(1,529)	(1,499)
Prior service benefit	(5,927)	(2,869)	(2,869)
Net gain	(39)	(175)	0
Net periodic benefit cost	$ 578	$ 5,649	$ 5,519

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Accounting for Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligation, Roll Forward Analysis
ARO liability at beginning of year	$ 92,911	$ 85,358	$ 78,037
Liabilities incurred	0	0	0
Liabilities settled	(793)	(85)	0
Revisions to estimate	(41,670)	(377)	0
Accretion expense	5,692	8,015	7,321
ARO liability at end of year	$ 56,140	$ 92,911	$ 85,358

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Summary of Significant Accounting Policies (Revenues) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Summary of Significant Accounting Policies [Abstract]
Accrued unbilled revenues	$ 19.6	$ 16.6

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Tables)

12 Months Ended

Dec. 31, 2011

Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant [Abstract]

Schedule of Property, Plant and Equipment and Finite-Lived Intangible Assets By Major Class

The table below presents the balance of each major class of depreciable assets at December 31, 2011 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	768,284	$	(240,862	)	$	527,422
Steam and other	557,286		(223,109		)	334,177
Total production	1,325,570		(463,971		)	861,599
Transmission	394,385		(238,940		)	155,445
Distribution	864,746		(308,644		)	556,102
General	141,921		(78,323		)	63,598
Intangible	63,151		(31,775		)	31,376
Total	$	2,789,773	$	(1,121,653	)	$	1,668,120

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

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):

2009	$	4,542
2010	6,312
2011	6,668
2012 (estimated)	6,124
2013 (estimated)	5,403
2014 (estimated)	4,292
2015 (estimated)	3,542
2016 (estimated)	3,045

Schedule of Jointly Owned Utility Plants

A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2011 and 2010 is as follows (in thousands):

	December 31, 2011						December 31, 2010
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	768,284		$	211,983		$	772,710		$	209,427
Accumulated depreciation	(240,862		)	(164,622		)	(225,461		)	(159,679		)
Construction work in progress	53,822			1,634			48,703			1,940
Total	$	581,244		$	48,995		$	595,952		$	51,688

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Accounting for Asset Retirement Obligations Accounting for Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Accounting for Asset Retirement Obligations [Abstract]

Changes In Estimated Probabilities Assumptions

The assumptions used to calculate the original ARO liability and the revised 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	%

Schedule of Asset Retirement Obligations

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 due to Palo Verde license extension.

	2011			2010			2009
ARO liability at beginning of year	$	92,911		$	85,358		$	78,037
Liabilities incurred	—			—			—
Liabilities settled	(793		)	(85		)	—
Revisions to estimate	(41,670		)	(377		)	—
Accretion expense	5,692			8,015			7,321
ARO liability at end of year	$	56,140		$	92,911		$	85,358

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash Flows From Operating Activities:
Net income	$ 103,539	$ 100,603	$ 66,933
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	81,331	81,011	74,946
Amortization of nuclear fuel	37,018	31,316	22,305
Extraordinary gain related to Texas regulatory assets, net of tax	0	(10,286)	0
Deferred income taxes, net	45,688	27,456	40,846
Allowance for equity funds used during construction	(8,161)	(10,816)	(9,311)
Other amortization and accretion	19,875	16,740	14,440
Other operating activities	1,036	(881)	1,154
Change in:
Accounts receivable	(4,663)	(1,303)	26,125
Inventories	(3,750)	1,143	2,135
Net overcollection (undercollection) of fuel revenues	(26,001)	958	64,875
Prepayments and other	(2,538)	(544)	(790)
Accounts payable	4,401	(9,634)	(1,988)
Taxes accrued	11,915	18,523	(17,704)
Interest accrued	24	1,816	2,764
Other current liabilities	(2,286)	(689)	750
Deferred charges and credits	(5,911)	(6,063)	(18,370)
Net cash provided by operating activities	251,517	239,350	269,110
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(178,041)	(169,966)	(209,974)
Cash additions to nuclear fuel	(39,551)	(34,277)	(34,904)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(13,009)	(17,487)	(15,340)
Nuclear fuel	(5,177)	(2,487)	(943)
Allowance for equity funds used during construction	8,161	10,816	9,311
Decommissioning trust funds:
Purchases, including funding of $8.3 million, $8.2 million, and $7.9 million, respectively	(95,441)	(73,192)	(90,118)
Sales and maturities	82,926	61,656	79,935
Proceeds from sale of investments in debt securities	2,000	0	0
Other investing activities	727	286	1,695
Net cash used for investing activities	(237,405)	(224,651)	(260,338)
Cash Flows From Financing Activities:
Repurchases of common stock	(86,508)	(33,726)	(24,105)
Dividends paid	(27,223)	0	0
Proceeds from issuance of long-term debt	0	110,000	0
Borrowings under the revolving credit facility:
Proceeds	120,450	37,628	186,471
Payments	(91,775)	(139,922)	(173,126)
Other financing activities	(32)	(1,285)	2,136
Net cash provided by (used for) financing activities	(85,088)	(27,305)	(8,624)
Net increase (decrease) in cash and cash equivalents	(70,976)	(12,606)	148
Cash and cash equivalents at beginning of period	79,184	91,790	91,642
Cash and cash equivalents at end of period	$ 8,208	$ 79,184	$ 91,790

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Common Stock (Tables)

12 Months Ended

Dec. 31, 2011

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Expense, Deferred Tax Benefit, and Current Tax Expense Related to Restricted Stock Awards

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards in 2011, 2010 and 2009 is presented below (in thousands):

	2011			2010			2009
Expense	$	2,258		$	1,589		$	1,537
Deferred tax benefit	790			556			538
Current tax expense (benefit) recognized (a)	(518		)	(169		)	134

_____________________

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

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity

The aggregate intrinsic value and fair value at grant date of restricted stock which vested in 2011, 2010 and 2009 is presented below (in thousands):

	2011		2010		2009
Aggregated intrinsic value	$	3,279	$	1,749	$	1,331
Fair value at grant date	1,799		1,265		1,714

Schedule of Nonvested Restricted Stock Units Activity

The unvested restricted stock transactions for 2011 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, 2010	143,371		$	18.30
Restricted stock awards	118,110		28.98
Lapsed restrictions and vesting	(103,096	)	17.45
Forfeitures	(2,200	)	23.20
Restricted shares outstanding at December 31, 2011	156,185		26.87		$	2,136	$	5,410

_______________________

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

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

The weighted average fair values per share at grant date for restricted stock awarded during 2011, 2010 and 2009 were:

	2011		2010		2009
Weighted average fair value per share	$	28.98	$	20.03	$	14.59

Schedule of Earnings Per Share, Basic and Diluted

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,
	2011			2010			2009
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	41,349,883			43,129,735			44,524,146
Dilutive effect of unvested performance awards	206,658			101,780			27,876
Dilutive effect of stock options	30,518			62,904			43,045
Diluted number of common shares outstanding	41,587,059			43,294,419			44,595,067
Basic net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income allocated to participating restricted stock	(471		)	(403		)	(240		)
Net income available to common shareholders	$	103,068		$	100,200		$	66,693
Diluted net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income reallocated to participating restricted stock	(469		)	(401		)	(240		)
Net income available to common shareholders	$	103,070		$	100,202		$	66,693
Basic net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.83			2.32			1.50
Basic net income per common share	$	2.49		$	2.32		$	1.50
Diluted net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.82			2.31			1.50
Diluted net income per common share	$	2.48		$	2.31		$	1.50

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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,
	2011	2010	2009
Restricted stock awards	81,653	75,270	66,628
Performance shares (a)	—	24,225	161,842
Stock options	—	—	53,610

_____________________

(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

Stock Options

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes the transactions in the Company’s stock options for 2011:

	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, 2010	101,246	$	12.82
Options exercised	53,910	12.83					$	692	$	327
Options outstanding at December 31, 2011	47,336	12.80		0.99	$	1,034
Exercisable at December 31, 2011	47,336	12.80		0.99	1,034

Performance Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

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) (in thousands)		Aggregate Intrinsic Value (in thousands)
Performance shares outstanding at December 31, 2010	219,800		$	15.86
Performance share awards	112,164		23.45
Performance shares vested	(36,350	)	17.27
Performance shares lapsed	—		—
Performance shares forfeited	—		—
Performance shares outstanding at December 31, 2011	295,614		18.57		$	1,825	$	10,240

_______________________

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

Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Performance-Based Units, Vested and Expected to Vest

Detail of performance shares vested follows:

Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Compensation Costs Expensed Period	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
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
January 1, 2010	30.0	%	9,525	662		2007-2009	193

Schedule of Share-based Compensation, Activity

A summary of information related to performance shares for 2011, 2010 and 2009 is presented below:

	2011		2010		2009
Weighted average per share grant date fair value per share of performance shares awarded	$	23.45	$	19.82	$	12.00
Fair value of performance shares vested (in thousands)	628		663		—
Intrinsic value of performance shares vested (in thousands)	1,032		193		—
Compensation expense (in thousands) (a)	1,573		988		727
Deferred tax expense related to compensation expense (in thousands)	551		346		254

_____________________

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

Repurchase of Equity

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Treasury Stock by Class [Table Text Block]

Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Twelve Months Ended December 31,		Authorized Shares
Shares repurchased	25,406,184		2,782,455
Cost, including commission (in thousands)	$	423,647	$	86,508
2010 Plan balance at December 31, 2010					676,271
2011 Plan repurchase shares authorized (b)					2,500,000
Total remaining shares available for repurchase at December 31, 2011					393,816

______________________

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

(b) On March 21, 2011, the Board of Directors authorized an additional repurchase of the Company’s common stock (the “2011 Plan”).

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Employee Benefits (Obligations and Funded Status of the Plan) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Retirement Plans
Change in plan assets:
Fair value of plan assets at end of year	$ 191,369	$ 171,341
Retirement Income Plan
Change in projected benefit obligation:
Benefit obligation at end of prior year	242,718	215,944
Service cost	6,590	5,888	5,414
Interest cost	12,871	12,507	11,942
Amendments	0	0	0
Actuarial loss	42,508	16,008
Benefits paid	(8,394)	(7,629)
Benefit obligation at end of year	296,293	242,718	215,944
Change in plan assets:
Fair value of plan assets at end of prior year	171,341	155,140
Actual return on plan assets	16,422	17,030
Employer contribution	12,000	6,800
Benefits paid	(8,394)	(7,629)
Fair value of plan assets at end of year	191,369	171,341	155,140
Funded status at end of year	(104,924)	(71,377)
Non-Qualified Retirement Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	24,008	21,767
Service cost	260	176	120
Interest cost	1,116	1,122	1,241
Amendments	0	838	0
Actuarial loss	2,980	1,822
Benefits paid	(1,817)	(1,717)
Benefit obligation at end of year	26,547	24,008	21,767
Change in plan assets:
Fair value of plan assets at end of prior year	0	0
Actual return on plan assets	0	0
Employer contribution	1,817	1,717
Benefits paid	(1,817)	(1,717)
Fair value of plan assets at end of year	0	0	0
Funded status at end of year	$ (26,547)	$ (24,008)

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Financial Instruments And Investments (Sale Of Securities And The Related Effects On Pre-Tax Income ) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Investment [Line Items]
Proceeds from sales of available-for-sale securities	$ 82,926	$ 61,656	$ 79,935
Gross realized gains included in pre-tax income	1,479	1,030	3,614
Gross realized losses included in pre-tax income	(721)	(889)	(238)
Other than Temporary Impairment Losses, Investments, Recognized in Earnings, before Tax, Available-for-sale Securities	(2,116)	(263)	(5,594)
Net gains (losses) in pre-tax income	(1,358)	(122)	(2,218)
Net unrealized holding gains (losses) included in accumulated other comprehensive income	1,570	6,665	12,816
Net gains (losses) reclassified out of accumulated other comprehensive income	1,358	122	2,218
Net gains (losses) in other comprehensive income	$ 2,928	$ 6,787	$ 15,034

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Supplemental Statements of Cash Flows Disclosures Supplemental Statements of Cash Flows Disclosures (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Statements of Cash Flow Disclosures [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

	Years Ended December 31,
	2011			2010		2009
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	48,664		$	47,783	$	46,836
Income taxes paid (refund), net	(6,260		)	7,343		8,596
Non-cash financing activities:
Grants of restricted shares of common stock	3,268			2,098		1,592
Issuance of performance shares	628			663		—
Acquisition of treasury stock for options exercised	500			—		—

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Narrative) (Details) (USD $)	0 Months Ended		6 Months Ended	12 Months Ended				0 Months Ended					12 Months Ended		1 Months Ended	0 Months Ended
	Oct. 18, 2011	Mar. 30, 2011	Sep. 30, 2011	Dec. 31, 2011 utilityplantunit	Dec. 31, 2010	Dec. 31, 2009	Apr. 21, 2011 utilityplantunit	Oct. 18, 2011 Minimum	Mar. 30, 2011 Minimum	Oct. 18, 2011 Maximum	Mar. 30, 2011 Maximum	Dec. 31, 2011 Palo Verde	Dec. 31, 2011 Palo Verde Participants utilityplantunit	Dec. 31, 2011 Four Corners Generating Station	Oct. 31, 2010 Suit Against Department of Energy for Spent Fuel	Jun. 18, 2010 Suit Against Department of Energy for Spent Fuel APS and Palo Verde Participants
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share				15.80%										7.00%
Jointly Owned Plant, Number of Participants													6
Jointly Owned Utility Plant, Number of Units				3
Number of Units With Renewed Operating Licenses							3
Utilities Operating Expense, Reduction of Depreciation and Amortization			$ 8,200,000
Utilities Operating Expense, Reduction of Asset Retirement Obligation Accretion Expense			3,100,000
Decommissioning Fund Investments				167,963,000	153,878,000
Third Party Decommission Cost Estimates Study Period, in Years				3 years
Estimated Decommissioning Costs		357,400,000
Public Utilities Property Plant and Equipment Estimated Useful life Extension									40 years		60 years
Decommission cost increase		33,000,000
Asset Retirement Obligation, Revision of Estimate				41,670,000	377,000	0
Litigation Settlement, Gross																30,000,000
Proceeds from Legal Settlements															4,800,000
Implementation Period of the NRC Task Force Recommendations, in Years	5 years
NRC Task Force Requirment Period to Provide Lessons Learned From Extended Offsite Loss of Power, in Months								24 months		30 months
Nuclear Energy Hazards Full Limit Of Liability Under Federal Law													12,600,000,000
Nuclear Energy Hazards Potential Liability													375,000,000
Maximum Assesment Per Reactor Nuclear Energy Incident												55,700,000	117,500,000
Maximum Assesment Per Reactor Nuclear Energy Incident Annual Limit												8,300,000	17,500,000
Aggregate Amount of Insurance for Decontamination and Property Damage													2,750,000,000
Retrospective Premium Adjustments Due to Nuclear Facility Losses												$ 9,570,000

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Income Taxes (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Income Tax [Line Items]
Period of Average Annual Book Income Before Taxes	3 years
Alternative Minimum Tax Benefit		$ 10,200,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	19,863,000	18,370,000
Other Noncash Income Tax Expense	4,800,000
Twenty Year Life
Income Tax [Line Items]
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward	21,100,000
Period of Operating Loss Carryforwards, In Years	20 years
Five Year Life
Income Tax [Line Items]
Unrecognized Tax Benefits Resulting in Net Operating Loss Carryforward	$ 600,000
Period of Operating Loss Carryforwards, In Years	5 years

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Utility plant:
Electric plant in service	$ 2,789,773	$ 2,522,862
Less accumulated depreciation and amortization	(1,121,653)	(1,047,498)
Net plant in service	1,668,120	1,475,364
Construction work in progress	167,394	285,086
Nuclear fuel; includes fuel in process of $49,545 and $47,746, respectively	171,433	150,774
Less accumulated amortization	(59,882)	(45,471)
Net nuclear fuel	111,551	105,303
Net utility plant	1,947,065	1,865,753
Current assets:
Cash and cash equivalents	8,208	79,184
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,015 and $2,885, respectively	76,348	71,685
Accumulated deferred income taxes	13,752	25,818
Inventories, at cost	40,222	36,132
Income taxes receivable	2,269	12,656
Undercollection of fuel revenues	9,130	0
Prepayments and other	4,810	4,543
Total current assets	154,739	230,018
Deferred charges and other assets:
Decommissioning trust funds	167,963	153,878
Regulatory assets	101,027	88,557
Other	26,057	26,560
Total deferred charges and other assets	295,047	268,995
Total assets	2,396,851	2,364,766
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,295,888 and 65,121,689 shares issued, and 156,185 and 143,371 restricted shares, respectively	65,452	65,265
Capital in excess of stated value	309,777	305,068
Retained earnings	887,174	810,858
Accumulated other comprehensive income (loss), net of tax	(77,505)	(33,177)
Stockholders Equity Subtotal Before Treasury Stock	1,184,898	1,148,014
Treasury stock, 25,492,919 and 22,693,995 shares, respectively, at cost	(424,647)	(337,639)
Common stock equity	760,251	810,375
Long-term debt	816,497	849,745
Total capitalization	1,576,748	1,660,120
Current liabilities:
Current maturities of long-term debt	33,300	0
Short-term borrowings under the revolving credit facility	33,379	4,704
Accounts payable, principally trade	51,704	41,795
Taxes accrued	30,700	29,172
Interest accrued	12,123	12,099
Overcollection of fuel revenues	2,105	18,976
Other	21,921	24,207
Total current liabilities	185,232	130,953
Deferred credits and other liabilities:
Accumulated deferred income taxes	299,475	286,730
Accrued pension liability	129,627	93,471
Accrued postretirement benefit liability	100,455	61,594
Asset retirement obligation	56,140	92,911
Regulatory liabilities	21,049	14,489
Other	28,125	24,498
Total deferred credits and other liabilities	634,871	573,693
Commitments and contingencies
Total capitalization and liabilities	$ 2,396,851	$ 2,364,766

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Summary of Significant Accounting Policies (Allowance For Doubtful Accounts) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Summary of Significant Accounting Policies [Abstract]
Balance at beginning of year	$ 2,885	$ 1,191	$ 3,123
Additions [Abstract]
Charged to costs and expense	6,209	4,756	3,289
Recovery of previous write-offs	2,034	852	1,316
Uncollectible receivables written off	8,113	3,914	6,537
Balance at end of year	$ 3,015	$ 2,885	$ 1,191

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Employee Benefits (Expected Future Benefit Payments) (Details) (USD $)	Dec. 31, 2011
Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 19,800,000
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2012	9,132,000
2013	9,967,000
2014	10,932,000
2015	11,924,000
2016	13,021,000
2017-2021	83,027,000
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2012	1,844,000
2013	1,813,000
2014	1,777,000
2015	1,758,000
2016	1,801,000
2017-2021	$ 9,430,000

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Financial Instruments And Investments (Unrealized Holding Losses Included In Pre-Tax Income) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Financial Instruments And Investments [Abstract]
Gross unrealized holding losses included In pre-tax income	$ (2,116)	$ (263)	$ (5,594)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parentheticals) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Purchases, funding	$ 8.3	$ 8.2	$ 7.9

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Employee Benefits (Fair Value Measurement Inputs) (Details) (Retirement Plans, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011	Dec. 31, 2011 Cash and Cash Equivalents	Dec. 31, 2010 Cash and Cash Equivalents	Dec. 31, 2011 US Treasury Securities	Dec. 31, 2010 US Treasury Securities	Dec. 31, 2011 Investment Contracts	Dec. 31, 2010 Investment Contracts	Dec. 31, 2011 Common Stock	Dec. 31, 2010 Common Stock	Dec. 31, 2010 Mutual Funds	Dec. 31, 2011 Mututal Funds - Fixed Income	Dec. 31, 2011 Mutual Funds - Equity	Dec. 31, 2011 Limited Partnership Interest in Real Estate		Dec. 31, 2010 Limited Partnership Interest in Real Estate		Dec. 31, 2009 Limited Partnership Interest in Real Estate	Dec. 31, 2011 Fair Value, Inputs, Level 1	Dec. 31, 2010 Fair Value, Inputs, Level 1	Dec. 31, 2011 Fair Value, Inputs, Level 1 Cash and Cash Equivalents	Dec. 31, 2010 Fair Value, Inputs, Level 1 Cash and Cash Equivalents	Dec. 31, 2011 Fair Value, Inputs, Level 1 US Treasury Securities	Dec. 31, 2010 Fair Value, Inputs, Level 1 US Treasury Securities	Dec. 31, 2011 Fair Value, Inputs, Level 1 Investment Contracts	Dec. 31, 2010 Fair Value, Inputs, Level 1 Investment Contracts	Dec. 31, 2011 Fair Value, Inputs, Level 1 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 1 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 1 Mutual Funds	Dec. 31, 2011 Fair Value, Inputs, Level 1 Mututal Funds - Fixed Income	Dec. 31, 2011 Fair Value, Inputs, Level 1 Mutual Funds - Equity	Dec. 31, 2011 Fair Value, Inputs, Level 1 Limited Partnership Interest in Real Estate		Dec. 31, 2010 Fair Value, Inputs, Level 1 Limited Partnership Interest in Real Estate		Dec. 31, 2011 Fair Value, Inputs, Level 2	Dec. 31, 2010 Fair Value, Inputs, Level 2	Dec. 31, 2011 Fair Value, Inputs, Level 2 Cash and Cash Equivalents	Dec. 31, 2010 Fair Value, Inputs, Level 2 Cash and Cash Equivalents	Dec. 31, 2011 Fair Value, Inputs, Level 2 US Treasury Securities	Dec. 31, 2010 Fair Value, Inputs, Level 2 US Treasury Securities	Dec. 31, 2011 Fair Value, Inputs, Level 2 Investment Contracts	Dec. 31, 2010 Fair Value, Inputs, Level 2 Investment Contracts	Dec. 31, 2011 Fair Value, Inputs, Level 2 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 2 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 2 Mutual Funds	Dec. 31, 2011 Fair Value, Inputs, Level 2 Mututal Funds - Fixed Income	Dec. 31, 2011 Fair Value, Inputs, Level 2 Mutual Funds - Equity	Dec. 31, 2011 Fair Value, Inputs, Level 2 Limited Partnership Interest in Real Estate		Dec. 31, 2010 Fair Value, Inputs, Level 2 Limited Partnership Interest in Real Estate		Dec. 31, 2011 Fair Value, Inputs, Level 3	Dec. 31, 2010 Fair Value, Inputs, Level 3	Dec. 31, 2011 Fair Value, Inputs, Level 3 Cash and Cash Equivalents	Dec. 31, 2010 Fair Value, Inputs, Level 3 Cash and Cash Equivalents	Dec. 31, 2011 Fair Value, Inputs, Level 3 US Treasury Securities	Dec. 31, 2010 Fair Value, Inputs, Level 3 US Treasury Securities	Dec. 31, 2011 Fair Value, Inputs, Level 3 Investment Contracts	Dec. 31, 2010 Fair Value, Inputs, Level 3 Investment Contracts	Dec. 31, 2011 Fair Value, Inputs, Level 3 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 3 Common Stock	Dec. 31, 2010 Fair Value, Inputs, Level 3 Mutual Funds	Dec. 31, 2011 Fair Value, Inputs, Level 3 Mututal Funds - Fixed Income	Dec. 31, 2011 Fair Value, Inputs, Level 3 Mutual Funds - Equity	Dec. 31, 2011 Fair Value, Inputs, Level 3 Limited Partnership Interest in Real Estate		Dec. 31, 2010 Fair Value, Inputs, Level 3 Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year	$ 171,341	$ 191,369	$ 6,708	$ 4,975	$ 24,178	$ 83,601	$ 608	$ 550	$ 70,893	$ 54,957	$ 19,501	$ 53,598	$ 26,873	$ 8,511	[1]	$ 7,757	[1]	$ 8,288	$ 182,250	$ 163,034	$ 6,708	$ 4,975	$ 24,178	$ 83,601	$ 0	$ 0	$ 70,893	$ 54,957	$ 19,501	$ 53,598	$ 26,873	$ 0	[1]	$ 0	[1]	$ 608	$ 550	$ 0	$ 0	$ 0	$ 0	$ 608	$ 550	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 8,511	$ 7,757	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 8,511	[1]	$ 7,757	[1]
Restriction Period To Sell Partnership Interest Minimum	5 years
Restriction Period To Sell Partnership Interest Maximum	7 years

[1] 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.

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Common Stock (Schedule of Restricted Stock Tax Expense and Deferred Tax) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferred tax benefit	$ 45,688,000		$ 27,456,000		$ 40,846,000
Capitalized Costs Related to Restricted Stock Award or Unit Expense	100,000		100,000		100,000
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expense	2,258,000		1,589,000		1,537,000
Deferred tax benefit	790,000		556,000		538,000
Current tax expense (benefit) recognized	$ (518,000)	[1]	$ (169,000)	[1]	$ 134,000	[1]
Restricted Stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Restricted Stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

[1] Any capitalized costs related to these expenses would be less than $0.1 million for all years.

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Employee Benefits (Weighted Average Assumptions- Accrued Postretirement Benefits - Other Postretirment Benefit Plans) (Details) (Accrued Postretirement Benefit, Other Postretirement Benefit Plans, Defined Benefit)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Accrued Postretirement Benefit | Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate	4.30%	5.50%
Initial	8.00%	8.50%
Ultimate	5.00%	5.00%
Year ultimate reached	2026	2018
Defined Benefit Plan, Effect of One Percentage Point Increase on Discount Rate	1.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation, Percentage	14.10%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Discount Rate	1.00%
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation, Percentage	17.90%

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Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule of Deferred Tax Assets and Liabilities

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2011 and 2010 are presented below (in thousands):

	December 31,
	2011			2010
Deferred tax assets:
Benefit of tax loss carryforwards	$	21,737		$	286
Alternative minimum tax credit carryforward	19,863			18,370
Pensions and benefits	87,946			62,821
Asset retirement obligation	20,100			33,904
Deferred fuel	—			7,317
Other	20,524			21,093
Total gross deferred tax assets	170,170			143,791
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(424,319		)	(359,838		)
Decommissioning	(22,633		)	(37,936		)
Deferred fuel	(2,493		)	—
Other	(6,448		)	(6,929		)
Total gross deferred tax liabilities	(455,893		)	(404,703		)
Net accumulated deferred income taxes	$	(285,723	)	$	(260,912	)

Schedule of Components of Income Tax Expense (Benefit)

The Company recognized income tax expense for 2011, 2010 and 2009 as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Income tax expense:
Federal:
Current	$	5,084		$	19,251		$	(10,123	)
Deferred	46,612			31,279			39,537
Total federal income tax	51,696			50,530			29,414
State:
Current	2,936			4,308			2,321
Deferred	(924		)	1,947			1,309
Total state income tax	2,012			6,255			3,630
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044

Schedule of Effective Income Tax Rate Reconciliation

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,
	2011			2010			2009
Federal income tax expense computed on income at statutory rate	$	55,036		$	55,086		$	34,992
Difference due to:
State taxes, net of federal benefit	1,308			4,066			2,360
AEFUDC	(2,295		)	(3,578		)	(3,051		)
Permanent tax differences	(303		)	(3,103		)	(618		)
Patient Protection and Affordable Care Act	—			4,787			—
Other	(38		)	(473		)	(639		)
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044
Effective income tax rate	34.2		%	36.1		%	33.1		%
Effective income tax rate without PPACA	34.2		%	33.0		%	33.1		%

Summary of Income Tax Contingencies

A reconciliation of the December 31, 2011, 2010 and 2009 amount of unrecognized tax benefits is as follows (in thousands):

	2011		2010		2009
Balance at January 1	$	7,300	$	600	$	500
Additions/(reductions) based on tax positions related to the current year	2,200		6,300		—
Additions for tax positions of prior years	—		400		400
Reductions for tax positions of prior years	—		—		(300		)
Balance at December 31	$	9,500	$	7,300	$	600

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Common Stock (Performance Share Summary) (Details) (Performance Shares, USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average per share grant date fair value per share of performance shares awarded	$ 23.45		$ 19.82		$ 12.00
Fair value of performance shares vested	$ 628		$ 663		$ 0
Intrinsic value of performance shares vested	1,032		193		0
Compensation expense	1,573	[1]	988	[1]	727	[1]
Deferred tax expense related to compensation expense	$ 551		$ 346		$ 254

[1] Includes cumulative adjustments for forfeiture of performance share awards by certain executives.

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Franchises and Significant Customers

12 Months Ended

Dec. 31, 2011

Franchises and Significant Customers [Abstract]

Franchises And Significant Customers

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 agreements 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

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 bases 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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Commitments, Contingencies and Uncertainties Commitments, Contingencies and Uncertainties (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Long-term Purchase Commitment

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 July 2031	August 2011
Power Purchase Agreement	Sun Edison 1		12	MW	25 years after operational start date	2012
Power Purchase Agreement	Sun Edison 2		10	MW	25 years after operational start date	2012
Power Purchase Agreement	NextEra Energy Resources		5	MW	July 2011 through June 2036	July 2011

Allowance for Emissions

The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):

Compliance Year	Amount
2010		$	370
2011		62

Environmental Loss Contingency Disclosure

The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):

	Years Ended December 31,
	2011			2010		2009
Clean Air Act (1)	$	716	—	$	615	$	810
Clean Water Act (2)	264			178		597

________________

(1)Includes $0.3 million related to alleged excess emissions at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009.

(2)2011 excludes a reduction of approximately $0.1 million related to an adjustment for estimated remediation costs for Copper generating station. 2009 also excludes a reduction of $0.6 million related to an adjustment for estimated remediation costs for a property previously owned by the Company.

Schedule of Future Minimum Rental Payments for Operating Leases

As of December 31, 2011, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2012	$	1,030
2013	951
2014	919
2015	477
2016	438

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Employee Benefits (Components of Accumulated Other Comprehensive Income) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	$ 20,144	$ (14,411)
Prior service cost	(30,647)	(36,574)
Total	$ (10,503)	$ (50,985)

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Supplemental Statements of Cash Flows Disclosures

12 Months Ended

Dec. 31, 2011

Supplemental Statements of Cash Flow Disclosures [Abstract]

Cash Flow, Supplemental Disclosures

Supplemental Statements of Cash Flows Disclosures

	Years Ended December 31,
	2011			2010		2009
	(In thousands)
Cash paid for:
Interest on long-term debt and borrowing under the revolving credit facility	$	48,664		$	47,783	$	46,836
Income taxes paid (refund), net	(6,260		)	7,343		8,596
Non-cash financing activities:
Grants of restricted shares of common stock	3,268			2,098		1,592
Issuance of performance shares	628			663		—
Acquisition of treasury stock for options exercised	500			—		—

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Common Stock (Antidilutive Shares and Options) (Details)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Restricted Stock
Common Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	81,653,000		75,270,000		66,628,000
Performance Shares
Common Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	[1]	24,225,000	[1]	161,842,000	[1]
Stock Options
Common Stock [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0		0		53,610,000
Performance Shares
Common Stock [Line Items]
Performance Shares Payout Level	100.00%

[1] 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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Franchises and Significant Customers Franchises and Significant Customers (Details)	12 Months Ended	1 Months Ended		12 Months Ended
	Dec. 31, 2011	Apr. 30, 1999 White Sands	Mar. 31, 2006 Holloman	Dec. 31, 2011 July 1, 2005 through August 1, 2010 El Paso		Dec. 31, 2011 August 1, 2010 through Present El Paso		Dec. 31, 2011 February 1, 2000 through Present Las Cruces		Dec. 31, 2011 Sales Revenue, Services, Net Military Bases
Franchises and Significant Customers [Line Items]
Percentage of Revenue From Franchise Fees				3.25%	[1]	4.00%	[1],[2]	2.00%	[1]
Percentage of Revenue Additional Franchise Fees, Restricted	0.75%
Concentration Risk, Percentage										5.00%
Contract Term To Provide Retail Electric Service		10 years
Contract Term to Provide Retail Electric Service			10 years

[1] Based on a percentage of revenue.

[2] 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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CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]
Balances at beginning of period at Dec. 31, 2008	$ 694,229	$ 64,733	$ 295,346	$ 643,322	$ (29,364)	$ (279,808)
Balances at beginning of period (in shares) at Dec. 31, 2008		64,732,652				19,848,900
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation (in shares)		114,703
Restricted common stock grants and deferred compensation	2,277	115	2,162
Performance share awards vested	0
Stock awards withheld for taxes	(165)	(8)	(157)
Stock awards withheld for taxes (in shares)		(8,249)
Forfeitures and lapsed restricted common stock (in shares)		(12,850)
Forfeitures and lapsed restricted common stock	(13)	(13)
Deferred taxes on stock incentive plan	328		328
Stock options exercised	3,768	267	3,501
Stock options exercised (in shares)		267,900
Net income	66,933			66,933
Other comprehensive income (loss)	(20,523)				(20,523)
Treasury stock acquired, at cost (in shares)						1,320,384
Treasury stock acquired, at cost	(24,105)					(24,105)
Balances at end of period at Dec. 31, 2009	722,729	65,094	301,180	710,255	(49,887)	(303,913)
Balances at end of period (in shares) at Dec. 31, 2009		65,094,156				21,169,284
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation (in shares)		112,891
Restricted common stock grants and deferred compensation	2,415	113	2,302
Performance share awards vested	663	10	653
Performance share awards vested (in shares)		9,525
Stock awards withheld for taxes	(247)	(11)	(236)
Stock awards withheld for taxes (in shares)		(10,261)
Forfeitures and lapsed restricted common stock (in shares)		(37,993)
Forfeitures and lapsed restricted common stock	(501)	(38)	(463)
Deferred taxes on stock incentive plan	350		350
Stock options exercised	1,379	97	1,282
Stock options exercised (in shares)		96,742
Net income	100,603			100,603
Other comprehensive income (loss)	16,710				16,710
Treasury stock acquired, at cost (in shares)						1,524,711
Treasury stock acquired, at cost	(33,726)					(33,726)
Balances at end of period at Dec. 31, 2010	810,375	65,265	305,068	810,858	(33,177)	(337,639)
Balances at end of period (in shares) at Dec. 31, 2010	65,121,689	65,265,060				22,693,995
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted common stock grants and deferred compensation (in shares)		118,110
Restricted common stock grants and deferred compensation	3,205	118	3,087
Performance share awards vested	628	41	587
Performance share awards vested (in shares)		40,895
Stock awards withheld for taxes	(739)	(24)	(715)
Stock awards withheld for taxes (in shares)		(23,702)
Forfeitures and lapsed restricted common stock (in shares)		(2,200)
Forfeitures and lapsed restricted common stock	(2)	(2)
Deferred taxes on stock incentive plan	1,112		1,112
Stock options exercised	692	54	638
Stock options exercised (in shares)		53,910
Net income	103,539			103,539
Other comprehensive income (loss)	(44,328)				(44,328)
Dividends declared	(27,223)			(27,223)
Treasury stock acquired, at cost (in shares)						2,798,924
Treasury stock acquired, at cost	(87,008)					(87,008)
Balances at end of period at Dec. 31, 2011	$ 760,251	$ 65,452	$ 309,777	$ 887,174	$ (77,505)	$ (424,647)
Balances at end of period (in shares) at Dec. 31, 2011	65,295,888	65,452,073				25,492,919

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CONSOLIDATED BALANCE SHEETS (Parentheticals) (USD $) In Thousands, except Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Nuclear fuel; fuel in process	$ 49,545	$ 47,746
Accounts receivable, principally trade, allowance for doubtful accounts	$ 3,015	$ 2,885
Common stock, stated value (in dollars per share)	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	65,295,888	65,121,689
Common stock, restricted shares	156,185	143,371
Treasury stock, shares	25,492,919	22,693,995

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Long-Term Debt and Financing Obligations (Notes)

12 Months Ended

Dec. 31, 2011

Long-Term Debt and Financing Obligations [Abstract]

Long-term Debt

Long-Term Debt and Financing Obligations

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

	December 31,
	2011			2010
	(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
4.80% 2005 Series A refunding bonds, due 2040 (5.32% 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
4.00% 2002 Series A refunding bonds, due 2032 (5.07% 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)	397,894			397,856
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,768			148,754
Total Senior Notes	546,662			546,610
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	849,797			849,745
Financing Obligations:
Revolving Credit Facility ($33,379 due in 2012) (4)	33,379			4,704
Total long-term debt and financing obligations	883,176			854,449
Current Portion (amount due within one year):
Current maturities of long-term debt	(33,300		)	—
Short-term borrowings under the revolving credit facility	(33,379		)	(4,704		)
	$	816,497		$	849,745

 _____________________

(1) Pollution Control Bonds (“PCBs”)

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 4.00% 2002 Series A must be remarketed in August 2012 and is shown as current maturities of long-term debt on the Company's 2011 balance sheet.

(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.

(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 2011.

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

Prior to November 15, 2011, the Company had available a $200 million credit facility with a four-year term ending September 2014. The credit facility provided for the financing of nuclear fuel, which was accomplished through the RGRT that borrowed under the facility to acquire and process nuclear fuel. The Company was obligated to repay the RGRT’s borrowings with interest. Any amounts not borrowed by the RGRT could have been borrowed by the Company for working capital needs.

On November 15, 2011, the Company and RGRT entered into an amended and restated 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. Under the terms of the RCF, the Company and RGRT have available $200 million of credit for a term ending September 23, 2016. The Company may request that the RCF be increased up to a total of $300 million during the term of the RCF, subject to lender approval.

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 2011. As of December 31, 2011, the total amount borrowed by RGRT was $13.4 million for nuclear fuel under the RCF, and $20.0 million was 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, 2011.

As of December 31, 2011, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2012	$	33,300
2013	—
2014	—
2015	15,000
2016	—

The $33.4 million outstanding on the RCF for working capital and general corporate purposes is anticipated to be paid in 2012.

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Employee Benefits (Weighted Average Assumptions - Net Periodic Benefit Cost) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	Jan. 03, 2011	Dec. 31, 2011	Dec. 31, 2011 Net Periodic Benefit Costs	Dec. 31, 2010 Net Periodic Benefit Costs	Dec. 31, 2009 Net Periodic Benefit Costs
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate			5.50%	5.90%	6.00%
Expected long-term return on plan assets	5.20%		5.20%	5.20%	5.90%
Initial			8.50%	8.50%	9.00%
Ultimate			5.00%	5.00%	5.00%
Year ultimate reached			2018	2017	2017
Annual Rate Increase of Covered Health Care Benefits		8.50%
Percentage of Gradual Decrease of Health Care Benefit Rates		5.00%
Defined Benefit Plan, One Percentage Point Change, Increase or Decrease		1.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Benefit Obligations		$ 22.8
Defined Benefit Plan, Effect of One Percentage Point Decrease on Benefit Obligations		18.3
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components		1.6
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components		$ 1.2

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Employee Benefits (Target Asset Allocation of Pension Fund) (Details) (Retirement Plans)	12 Months Ended
	Dec. 31, 2011
Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Equity securities	50.00%
Fixed income	45.00%
Alternative investments	5.00%
Total	100.00%

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Employee Benefits (Accumulated Other Comprehensive Income Recognized in Net Periodic Benefit Cost in Next Fiscal Year) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	$ 11,300
Prior service cost	20
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss	560
Prior service cost	$ 90

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Selected Quarterly Financial Data (Unaudited) Selected Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2010		Sep. 30, 2010		Jun. 30, 2010		Mar. 31, 2010		Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Selected Quarterly Financial Data
Operating revenues	$ 191,663	[1]	$ 307,633	[1]	$ 242,605	[1]	$ 176,112	[1]	$ 181,344	[1]	$ 280,342	[1]	$ 211,397	[1]	$ 204,168	[1]	$ 918,013	$ 877,251	$ 827,996
Operating income	15,994		102,215		58,121		14,473		13,784		84,098		40,477		30,603		190,803	168,962	133,165
Income before extraordinary gain	5,453		58,321		32,990		6,775		7,466		49,896		21,507		11,449		103,539	90,317	66,933
Extraordinary gain related to Texas regulatory assets, net of tax	0		0		0		0		0		10,286		0		0		0	10,286	0
Net income	$ 5,453		$ 58,321		$ 32,990		$ 6,775		$ 7,466		$ 60,182		$ 21,507		$ 11,449		$ 103,539	$ 100,603	$ 66,933
Basic earnings per share:
Income before extraordinary item (in dollars per share)	$ 0.14		$ 1.41		$ 0.78		$ 0.16		$ 0.18		$ 1.16		$ 0.49		$ 0.26		$ 2.49	$ 2.08	$ 1.50
Extraordinary gain related to Texas regulatory assets, net of tax (in dollars per share)	$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.24		$ 0.00		$ 0.00		$ 0.00	$ 0.24	$ 0.00
Net income (in dollars per share)	$ 0.14		$ 1.41		$ 0.78		$ 0.16		$ 0.18		$ 1.40		$ 0.49		$ 0.26		$ 2.49	$ 2.32	$ 1.50
Diluted earnings per share:
Income before extraordinary gain (in dollars per share)	$ 0.13		$ 1.40		$ 0.78		$ 0.16		$ 0.17		$ 1.15		$ 0.49		$ 0.26		$ 2.48	$ 2.07	$ 1.50
Extraordinary gain related to Texas regulatory assets, net of tax (in dollars per share)	$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.24		$ 0.00		$ 0.00		$ 0.00	$ 0.24	$ 0.00
Net income (in dollars per share)	$ 0.13		$ 1.40		$ 0.78		$ 0.16		$ 0.17		$ 1.39		$ 0.49		$ 0.26		$ 2.48	$ 2.31	$ 1.50
Dividends declared per share of common stock	$ 0.22		$ 0.22		$ 0.22		$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.00		$ 0.66	$ 0.00	$ 0.00

[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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Document And Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2011	Jan. 31, 2012	Jun. 30, 2011
Document Information [Line Items]
Entity Registrant Name	EL PASO ELECTRIC CO /TX/
Entity Central Index Key	0000031978
Trading Symbol	EE
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		40,119,381
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1,330,697,564

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Tax Disclosure

Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2011 and 2010 are presented below (in thousands):

	December 31,
	2011			2010
Deferred tax assets:
Benefit of tax loss carryforwards	$	21,737		$	286
Alternative minimum tax credit carryforward	19,863			18,370
Pensions and benefits	87,946			62,821
Asset retirement obligation	20,100			33,904
Deferred fuel	—			7,317
Other	20,524			21,093
Total gross deferred tax assets	170,170			143,791
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(424,319		)	(359,838		)
Decommissioning	(22,633		)	(37,936		)
Deferred fuel	(2,493		)	—
Other	(6,448		)	(6,929		)
Total gross deferred tax liabilities	(455,893		)	(404,703		)
Net accumulated deferred income taxes	$	(285,723	)	$	(260,912	)

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

The Company recognized income tax expense for 2011, 2010 and 2009 as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Income tax expense:
Federal:
Current	$	5,084		$	19,251		$	(10,123	)
Deferred	46,612			31,279			39,537
Total federal income tax	51,696			50,530			29,414
State:
Current	2,936			4,308			2,321
Deferred	(924		)	1,947			1,309
Total state income tax	2,012			6,255			3,630
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044

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 2011 or 2009. As of December 31, 2011, the Company had $19.9 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2011, the Company had tax loss carryforwards of $21.1 million and $0.6 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,
	2011			2010			2009
Federal income tax expense computed on income at statutory rate	$	55,036		$	55,086		$	34,992
Difference due to:
State taxes, net of federal benefit	1,308			4,066			2,360
AEFUDC	(2,295		)	(3,578		)	(3,051		)
Permanent tax differences	(303		)	(3,103		)	(618		)
Patient Protection and Affordable Care Act	—			4,787			—
Other	(38		)	(473		)	(639		)
Total income tax expense	53,708			56,785			33,044
Tax expense classified as extraordinary gain	—			(5,769		)	—
Total income tax expense before extraordinary item	$	53,708		$	51,016		$	33,044
Effective income tax rate	34.2		%	36.1		%	33.1		%
Effective income tax rate without PPACA	34.2		%	33.0		%	33.1		%

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 2007 and in the state jurisdictions for years prior to 1998. A deficiency notice relating to the Company’s 1998 through 2003 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 Patient Protection and Affordable Care Act (“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 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. The Company recorded an additional unrecognized tax position of $2.2 million and $6.3 million, respectively, related to the change in accounting method in 2011 and 2010. An additional unrecognized tax position may be recognized after the IRS audits the 2009 and 2010 tax returns. A reconciliation of the December 31, 2011, 2010 and 2009 amount of unrecognized tax benefits is as follows (in thousands):

	2011		2010		2009
Balance at January 1	$	7,300	$	600	$	500
Additions/(reductions) based on tax positions related to the current year	2,200		6,300		—
Additions for tax positions of prior years	—		400		400
Reductions for tax positions of prior years	—		—		(300		)
Balance at December 31	$	9,500	$	7,300	$	600

If recognized, $1.1 million of the unrecognized tax position at December 31, 2011, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $0.1 million for the year ended December 31, 2009.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the years ended December 31, 2011, 2010 and 2009, the Company recognized expense of $0.2 million and benefits of approximately $0.1 million and $0.2 million, respectively, in interest. The Company had approximately $0.4 million and $0.2 million for the payment of interest and penalties accrued at December 31, 2011 and 2010, respectively.

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Commitments, Contingencies and Uncertainties (Costs Incurred To Comply With Federal Environment Statutes) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Site Contingency [Line Items]
Cost Related to Alleged Excess Emissions At Generating Station					$ 300,000
Reduction of Environmental Cost Recognized	100,000				600,000
Clean Air Act
Site Contingency [Line Items]
Environmental remediation expense	716,000	[1]	615,000	[1]	810,000	[1]
Clean Water Act
Site Contingency [Line Items]
Environmental remediation expense	$ 264,000	[2]	$ 178,000	[2]	$ 597,000	[2]

[1] Includes $0.3 million related to alleged excess emissions at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009.

[2] 2011 excludes a reduction of approximately $0.1 million related to an adjustment for estimated remediation costs for Copper generating station. 2009 also excludes a reduction of $0.6 million related to an adjustment for estimated remediation costs for a property previously owned by the Company.

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Employee Benefits (Recognized in Other Comprehensive Income and Net Periodic Benefit Costs - Retirement Plans) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ 45,547	$ 17,372	$ 50,448
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ 4,356	$ 3,958	$ 3,253

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating revenues	$ 918,013	$ 877,251	$ 827,996
Energy expenses:
Fuel	223,507	199,829	185,837
Purchased and interchanged power	75,149	91,916	108,603
Cost of services, energy services	298,656	291,745	294,440
Operating revenues net of energy expenses	619,357	585,506	533,556
Other operating expenses:
Other operations	229,570	224,221	215,841
Maintenance	62,092	56,823	59,606
Depreciation and amortization	81,331	81,011	74,946
Taxes other than income taxes	55,561	54,489	49,998
Utilities operating expense	428,554	416,544	400,391
Operating income	190,803	168,962	133,165
Other income (deductions):
Allowance for equity funds used during construction	8,161	10,816	9,311
Investment and interest income, net	5,664	5,315	3,813
Miscellaneous non-operating income	885	1,368	1,107
Miscellaneous non-operating deductions	(3,187)	(3,206)	(3,483)
Nonoperating income (expense)	11,523	14,293	10,748
Interest charges (credits):
Interest on long-term debt and revolving credit facility	54,115	50,826	50,512
Other interest	989	254	396
Capitalized interest	(5,177)	(2,487)	(943)
Allowance for borrowed funds used during construction	(4,848)	(6,671)	(6,029)
Interest expense	45,079	41,922	43,936
Income before income taxes and extraordinary item	157,247	141,333	99,977
Income tax expense	53,708	51,016	33,044
Income before extraordinary item	103,539	90,317	66,933
Extraordinary gain related to Texas regulatory assets, net of tax	0	10,286	0
Extraordinary Item, Gain (Loss), Net of Tax, Attributable to Parent	0	10,286	0
Net income	$ 103,539	$ 100,603	$ 66,933
Basic earnings per share:
Income before extraordinary item (in dollars per share)	$ 2.49	$ 2.08	$ 1.50
Extraordinary gain related to Texas regulatory assets, net of tax (in dollars per share)	$ 0.00	$ 0.24	$ 0.00
Net income (in dollars per share)	$ 2.49	$ 2.32	$ 1.50
Diluted earnings per share:
Income before extraordinary item (in dollars per share)	$ 2.48	$ 2.07	$ 1.50
Extraordinary gain related to Texas regulatory assets, net of tax (in dollars per share)	$ 0.00	$ 0.24	$ 0.00
Net income (in dollars per share)	$ 2.48	$ 2.31	$ 1.50
Dividends declared per share of common stock	$ 0.66	$ 0.00	$ 0.00
Weighted average number of shares outstanding	41,349,883	43,129,735	44,524,146
Weighted average number of shares and dilutive potential shares outstanding	41,587,059	43,294,419	44,595,067

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities [Abstract]

Schedule of Regulatory Assets and Liabilities

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, 2011		December 31, 2010
Regulatory assets
Regulatory tax assets (a)	(b)	$	52,281	$	37,230
Loss on reacquired debt (c)	May 2035	20,044		20,897
Final coal reclamation (a)	July 2016	6,655		10,282
Nuclear fuel postload daily financing charge	(d)	3,470		2,007
Unrecovered issuance costs due to reissuance of PCBs (c)	April 2040	578		599
Texas energy efficiency	(e)	4,497		5,460
Texas 2009 rate case costs (f)	June 2012	1,146		3,298
Texas 2012 rate case costs	(g)	648		—
Texas military base discount and recovery factor	(h)	2,526		761
New Mexico 2009 rate case procurement plan costs (f)	December 2011	—		232
New Mexico procurement plan costs	(g)	139		122
New Mexico 2009 rate case renewable energy credits (f)	December 2011	—		1,139
New Mexico renewable energy credits	(g)	2,884		930
New Mexico 2009 rate case costs (f)	December 2012	253		506
New Mexico 2010 FPPCAC audit	(g)	427		—
New Mexico Palo Verde deferred depreciation	(b)	5,176		4,773
New Mexico energy efficiency	(e)	303		321
Total regulatory assets		$	101,027	$	88,557
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	16,138	$	9,326
Accumulated deferred investment tax credit (i)	(b)	4,911		5,163
Total regulatory liabilities		$	21,049	$	14,489

________________

(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 30 years beginning in 2005.

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

(e) This asset is recovered 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.

(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.

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Regulation (Notes)

12 Months Ended

Dec. 31, 2011

Public Utilities, General Disclosures [Abstract]

Regulation

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 transactions and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The filing included a base rate increase which was based upon an adjusted test year ended June 30, 2009.

On July 30, 2010, the PUCT approved a settlement in the 2009 Texas retail rate case in PUCT Docket No. 37690. The settlement called for an annual non-fuel base rate increase of $17.15 million effective for usage beginning July 1, 2010. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. This increase was partially offset by the provision that, consistent with a prior rate agreement, effective July 1, 2010, the Company shares 90% of off-system sales margins with customers and retains 10% of such margins. Previously, the Company retained 75% of off-system sales margins. All additions to electric plant in service since June 30, 1993 through June 30, 2009 were deemed to be reasonable and necessary with the exception of one small addition. The Company's new customer information system completed in April 2010 was also included in base rates with a 10-year amortization. The settlement provided for the reconciliation of fuel costs incurred through June 30, 2009 except for the recovery of final Four Corners' coal mine reclamation costs. The fuel reconciliation (Docket No. 38361, discussed below) was bifurcated from the rate case to allow for litigation of the final coal mine reclamation costs. The PUCT also approved the use of a formula-based fuel factor which provides for more timely recovery of fuel costs. The PUCT approved a $19.7 million or 11% reduction in the Company's fixed fuel factor as the initial rate under the approved fuel factor formula. The PUCT also approved an energy efficiency cost-recovery factor that includes the recovery of deferred energy efficiency costs over a three-year period.

2012 Texas Retail Rate Case. The Company filed a request with the PUCT (Docket No. 40094), the City of El Paso, and other Texas cities on February 1, 2012 for a $26.3 million increase in rates charged to customers in Texas. The rate filing was made in response to a resolution adopted by the El Paso City Council requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The City has until August 4, 2012 to make a determination regarding the Company's base rates in the City of El Paso. The rate filing used a historical test year ended September 30, 2011, adjusted for known and measurable items, and a return on equity of 10.6%. The filing at the PUCT also includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.

On November 15, 2011, the El Paso City Council adopted a resolution which established current rates as temporary rates for the Company's customers residing within the city limits of El Paso. Temporary rates will be effective from November 15, 2011 until a final determination is made by the PUCT on the Company's rates in the rate proceeding initiated by the City's Show Cause Order. Upon a final determination by the PUCT, the PUCT may order a refund to customers of money collected in excess of the rate finally ordered, including interest, or shall authorize the Company to surcharge bills to recover the amount, including interest, by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered. The rates proposed by the Company in the Texas rate case included increases for some customer classes and decreases for other customer classes. As a result, consistent implementation of the proposed rates may require the PUCT to reflect the differences in temporary and final rates from November 15, 2011 for each affected class.

While cities in Texas have jurisdiction over rates in their city limits, the PUCT has appellate authority over city rate decisions on a “de novo” basis; therefore, the ultimate authority to set the Company's Texas electric rates is vested in the PUCT. The Company cannot predict the outcome of this proceeding. If the rate case results in implementing lower rates, the resulting lower rates would have a negative impact on the Company's revenues, net income and cash from operations.

Fuel Reconciliation Case (Severed from 2009 Rate Case). Pursuant to the stipulation in the Company's 2009 rate case, the PUCT established Docket No. 38361 to address the one fuel reconciliation issue not settled by the parties. That single issue was a determination of the proper amount of the Four Corners' coal mine final reclamation costs to be recovered from the Company's Texas retail customers. The hearing on the merits of the case was held on August 11, 2010. On November 23, 2010 the Administrative Law Judge (the “ALJ”) issued the Proposal for Decision which approved the Company's request. The PUCT issued a final order approving the Proposal for Decision on January 27, 2011.

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. The Company received approval on July 30, 2010 in PUCT Docket No. 37690 (discussed above), 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.

The Company has filed the following petitions 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 dates the Company filed the petitions and the dates a final order was issued by the PUCT approving the refunds to customers. The fuel cost over-recovery periods represent the months in which the over-recoveries took place and the refund periods represent the billing month(s) in which customers received the refund amounts shown, including interest:

Docket No.	Date Filed	Date Approved	Recovery Period	Refund Period	Refund Amount (In thousands)
37788	December 17, 2009	February 11, 2010	September – November 2009	February 2010	$	11,800
38253	May 12, 2010	July 15, 2010	December 2009 – March 2010	July – August 2010	11,100
38802	October 20, 2010	December 16, 2010	April – September 2010	December 2010	12,800
39159	February 18, 2011	May 3, 2011	October – December 2010	April 2011	11,800

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

Docket No.	Date Filed	Date Approved	Increase (Decrease) in Fuel Factor		Effective Billing Month
38895	November 23, 2010	January 6, 2011	(14.7	)%	January 2011
39599	July 15, 2011	August 30, 2011	9.4	%	August 2011

As noted above, the rate filing filed with the PUCT on February 1, 2012 (Docket No. 40094), includes a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. However, this filing does not request a change in the fixed fuel factor.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2012. On May 2, 2011, the Company filed with the PUCT an application for approval to revise its energy efficiency cost recovery factor (“EECRF”), which was assigned PUCT Docket No. 39376. A unanimous settlement resolving all issues was filed with the PUCT on July 15, 2011. The settlement allows the Company to recover $8.3 million and supports the Company's request to revise its demand and energy goals and EECRF cost caps as well as the Company's request to increase its 2012 EECRF, effective beginning with the first billing cycle of its January 2012 billing month. A final order in the case was issued August 23, 2011, approving the settlement.

Petition for Approval to Revise Military Base Discount Recovery Factor. On July 14, 2011, the Company filed with the PUCT a petition requesting approval to revise its Military Base Discount Recovery Factor (“MBDRF”) tariff to account for under-recovery of discount charges during 2010 and for 2011 discounts. A final order was issued January 12, 2012 revising the MBDRF to 0.936% and allowing $3.9 million dollars of under-recovered discount charges to begin February 1, 2012.

Application for a Certificate of Convenience and Necessity (“CCN”) for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned PUCT Docket No. 38717. A unanimous settlement to approve the CCN was filed on March 2, 2011, and a final order granting the CCN was approved on April 8, 2011.

Project to Investigate Early February 2011 Outages and Curtailments. On February 8, 2011, the PUCT opened Project No. 39134, Investigation into Power Outages in El Paso Electric's Service Territory. In this project, the PUCT is investigating the Company's power plant outages and customer curtailments that occurred February 2-4, 2011, as a result of the extreme cold weather in the El Paso area. The PUCT Staff conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event. On May 13, 2011, the PUCT Staff issued a report stating that, as of then, it had not identified violations by the Company of the Texas electric utility regulatory statute or PUCT rules. The report also stated that the PUCT Staff would continue to monitor the extreme cold weather event results and subsequent forthcoming information as the Company and other regulatory agencies complete their ongoing investigations.

On February 15, 2011, the City Council of El Paso passed a motion that, upon the conclusion of other hearings and investigations into the extreme cold weather event, the Mayor would call for Special City Council meetings or public hearings to evaluate how the three utility companies operating within the city, including the Company, performed during the extreme weather event. The El Paso City Council retained a consultant to assess the Company's activities during the weather event and the Company's subsequent actions to prevent outages during a similar future event. The El Paso City Council's consultant presented the following three recommendations to the El Paso City Council on December 20, 2011: (i) request the Company to prepare and present an updated reliability study; (ii) request the Company and El Paso Water Utilities to present their coordinated plans for power and water supply to critical loads during severe weather events; and (iii) request the Company to file an updated emergency operations plan with both the PUCT and the El Paso City Council which will be completed in 2012. The El Paso City Council unanimously passed a motion to approve the three recommendations. At the January 10, 2012 El Paso City Council Meeting, the Company presented information requested in recommendations (i) and (ii) above.

Application of El Paso Electric Company to Amend its Certificate of Convenience and Necessity for Five Solar Power Generation Projects. On December 9, 2011, the Company filed a petition seeking a CCN to construct five solar powered generation projects, totaling approximately 2.6MW, at four locations within the City of El Paso and one location in the Town of Van Horn. This case was assigned PUCT Docket No. 39973 and is still pending.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On May 29, 2009, the Company filed a general rate case using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT. A comprehensive unopposed stipulation (the “2009 New Mexico Stipulation”) was reached in this general rate case and filed on October 8, 2009. The 2009 New Mexico Stipulation provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The new rate structure resulted in net increases in base rates during the peak summer season of May through October and net decreases in base rates during November through April. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and a revision of depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company's Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) without conditions or variance. In addition, it modified the market pricing of capacity and energy provided by Palo Verde Unit 3 using a methodology based upon a previous purchased power contract with Credit Suisse Energy, LLC. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation, and the stipulated rates went into effect with January 2010 bills.

Application for Approval to Recover Regulatory Disincentives and Incentives. On August 31, 2010, the Company filed an application for approval of its proposed rate design methodology to recover regulatory disincentives and incentives associated with the Company's energy efficiency and load management programs in New Mexico. On March 18, 2011, the Company entered into an uncontested stipulation which would provide for a rate per kWh of energy efficiency savings that would be recovered through the efficient use of energy rider. A hearing on the uncontested stipulation was held on April 26, 2011 and briefs were filed on September 26, 2011. A final order was issued on November 22, 2011 in which the NMPRC did not adopt the unopposed stipulation, but modified the structure of the energy rider to reduce the return to two percent and made the mechanism temporary.  The Company filed a Notice of Appeal with the Supreme Court of the State of New Mexico on January 20, 2012 on the grounds that the NMPRC's decision is arbitrary and without substantial evidence.

Application for a CCN for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company's existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned NMPRC Case No. 10-00301-UT. On April 13, 2011 an unopposed stipulation was filed in this case seeking approval of a CCN for the Company to construct, own and operate the 87 MW generating unit. A final order on this case approving the CCN was issued on June 23, 2011.

Application for Approval of 2011 New and Modified Energy Efficiency Programs. On February 15, 2011, the Company filed its Application for Approval of New and Modified Energy Efficiency Programs for 2011 with the NMPRC. On June 22, 2011, parties to this case entered into a partial stipulation, agreeing on all issues, except for a military base free-ridership issue. On June 24, 2011, the New Mexico Attorney General filed a statement in opposition to the proposed partial stipulation. On January 25, 2012, a hearing examiner issued a recommended decision modifying the stipulation by approving the Energy Efficiency programs and budgets with the exception of the Commercial Lighting Program, approving the adder for 2011 but not for 2012 or 2013 and excluding the Military Research & Development Class from participation in the rate rider and reducing the Company's required saving goals accordingly. On February 2, 2012, the Company filed certain exceptions to the recommended decision and requested an interim order related to this matter.

2011 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2011, the Company filed its Application for Approval of its 2011 Renewable Procurement Plan with the NMPRC, which was assigned NMPRC Case No. 11-00263-UT. The filing identified renewable resources intended to meet the Company's Renewable Portfolio Standard (“RPS”) requirements in 2012 and 2013. The renewable resources in the 2011 Renewable Procurement Plan, which were previously approved by the NMPRC, will allow the Company to meet the full RPS requirement of 10% of the Company's jurisdictional retail energy sales for 2012 and 2013. The Company's 2011 Renewable Procurement Plan also addresses the diversity targets in 2012 and 2013 required by NMPRC Rule 572 and demonstrates that the Company will meet those targets. The 2011 Renewable Procurement Plan also demonstrates that the Company will meet its solar diversity target in 2012 and comply with the terms of a previously-approved variance for 2011. A hearing in this case was held on October 13, 2011. A final order was issued on December 15, 2011 approving the 2011 Renewable Procurement Plan.

Investigation into Rates for Church Customers. On July 12, 2011, the NMPRC initiated an investigation into the rates the Company charges its church customers which were approved in Case No. 09-00171-UT. The investigation, Case No. 11-00276-UT, was ordered to determine whether the Company's rates to its church customers are unjust and unreasonable and should be revised. The Company filed a response on August 1, 2011. A mediation conference was held on August 23, 2011 which resulted in an Unopposed Joint Stipulation, filed on October 14, 2011. The stipulation limits billing impacts to religious organizations that take service under the Company's standard small commercial rate. The stipulation was approved by the NMPRC on October 27, 2011.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the NMPRC in Case No. 11-00349-UT to amend and restate the Company's $200 million revolving credit facility ("RCF"), which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and Rio Grande Resources Trust ("RGRT") amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million during the term of the RCF, subject to lender's approval. All other terms remain substantially the same.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company's transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in Arizona. The Company asserted that TEP's rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Company's favor, finding that TEP does not have transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP's request for a rehearing of the FERC's decision was granted in part and denied in part in an order issued October 4, 2006, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.

On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time.

The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for service relating to the LEF. On December 3, 2008, the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC's decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company's transmission system on a going forward basis. On July 7, 2010, the FERC denied the Company's request for rehearing. On July 23, 2010, the Company filed a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) and on August 18, 2010, TEP filed a motion to intervene in the proceeding. On January 14, 2011, the Company and TEP filed a joint consent motion, asking the Court to hold the proceedings in abeyance while the parties engaged in settlement discussions. The Court granted the motion on January 19, 2011.

On August 31, 2011, the FERC issued an order approving a settlement between TEP and the Company that became effective November 1, 2011. The settlement reduces TEP's transmission rights under the Transmission Agreement from 200 MW to 170 MW, and TEP and the Company have entered into two new firm transmission capacity agreements at applicable tariff rates for a total of 40 MW. Those two new service agreements were entered into and became effective November 1, 2011. Also under the terms of the settlement, TEP made a lump-sum cash payment to the Company of approximately $5.4 million for the period February 1, 2006 through September 30, 2011, including interest income. This adjustment was recorded in the three months ended September 30, 2011. The Company shared with its customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries. As part of the settlement, the Company withdrew its appeal before the Court of Appeals.

In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. As part of the settlement, this lawsuit was dismissed.

With the implementation of the settlement effective November 1, 2011, these matters between the Company and TEP were fully resolved.

Inquiry into Early February 2011 Outages and Curtailments. On February 14, 2011, the FERC directed its staff to initiate an inquiry into power plant outages and customer curtailments by power generators and gas suppliers in the Southwestern United States, including the Company, in early February 2011, as a result of the extreme cold weather. The FERC specifically stated that its inquiry is not an enforcement investigation. On August 16, 2011, the FERC released its staff report, Docket No. AD11-9-000, where it made recommendations to help prevent a recurrence of such outages in the future, and making no finding of violations or assessments of penalties.

Revolving Credit Facility and Guarantee of Debt. On October 13, 2011, the Company received final approval from the FERC in Docket No. ES11-43-000 to amend and restate the Company's $200 million RCF, which includes an option, subject to lender's approval, to expand the size to $300 million, and to incrementally issue up to $300 million of long-term debt as and when needed. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides the Company with the flexibility to access the debt capital markets when needed and when conditions are favorable.

On November 15, 2011, the Company and RGRT amended and restated the $200 million unsecured 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 amended and restated RCF reduces borrowing costs and extends the maturity from September 2014 to September 2016. The Company still has the ability to request that the RCF be increased to $300 million, subject to lender's approval. All other terms remain substantially the same.

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

Nuclear Regulatory Commission ("NRC"). The NRC has jurisdiction over the Company's licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.

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.

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Financial Instruments and Investments (Notes)

12 Months Ended

Dec. 31, 2011

Financial Instruments And Investments [Abstract]

Financial Instruments and Investments

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,
	2011				2010
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	206,756	$	193,135	$	192,924
Senior Notes	546,662		700,371		546,610		574,700
RGRT Senior Notes (1)	110,000		116,985		110,000		110,371
RCF (1)	33,379		33,379		4,704		4,704
Total	$	883,176	$	1,057,491	$	854,449	$	882,699

 __________________

(1) Nuclear fuel financing as of December 31, 2011 is funded through the $110.0 million RGRT Senior Notes and $13.4 million under the RCF and $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 quarter 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 2012, 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, 2011, 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, 2011, 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 $168.0 million and $153.9 million at December 31, 2011 and 2010, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands):

	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 (1):
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	)

 ____________________

(1) Includes approximately 96 securities.

	December 31, 2010
	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	$	2,290	$	(51	)	$	441	$	(27	)	$	2,731	$	(78	)
U.S. Government Bonds	9,583		(124		)	—		—			9,583		(124		)
Municipal Obligations	13,145		(278		)	3,763		(145		)	16,908		(423		)
Corporate Obligations	1,855		(18		)	—		—			1,855		(18		)
Total Debt Securities	26,873		(471		)	4,204		(172		)	31,077		(643		)
Common stock	6,943		(774		)	4,303		(420		)	11,246		(1,194		)
Total Temporarily Impaired Securities	$	33,816	$	(1,245	)	$	8,507	$	(592	)	$	42,323	$	(1,837	)

 ______________________

(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):

	December 31, 2011				December 31, 2010
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	25,077	$	1,220	$	18,472	$	793
U.S. Government Bonds	10,263		972		10,450		183
Municipal Obligations	30,310		1,792		15,633		592
Corporate Obligations	7,641		459		7,223		362
Total Debt Securities	73,291		4,443		51,778		1,930
Common Stock	62,479		15,681		56,770		14,142
Cash and Cash Equivalents	3,739		—		3,007		—
Total	$	139,509	$	20,124	$	111,555	$	16,072

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 to 7 years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2011 is as follows (in thousands):

	Total		2012		2013 through 2016		2017 through 2021		2022 and Beyond
Municipal Debt Obligations	$	37,316	$	1,009	$	12,892	$	14,252	$	9,163
Corporate Debt Obligations	12,400		1,368		3,630		4,338		3,064
U.S. Government Bonds	12,776		1,316		1,685		6,844		2,931

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, 2011, 2010, and 2009 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):

	2011			2010			2009
Gross unrealized holding losses included in pre-tax income	$	(2,116	)	$	(263	)	$	(5,594	)

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, 2011, 2010, and 2009 and the related effects on pre-tax income are as follows (in thousands):

	2011			2010			2009
Proceeds from sales of available-for-sale securities	$	82,926		$	61,656		$	79,935
Gross realized gains included in pre-tax income	$	1,479		$	1,030		$	3,614
Gross realized losses included in pre-tax income	(721		)	(889		)	(238		)
Gross unrealized losses included in pre-tax income	(2,116		)	(263		)	(5,594		)
Net losses in pre-tax income	$	(1,358	)	$	(122	)	$	(2,218	)
Net unrealized holding gains included in accumulated other comprehensive income	$	1,570		$	6,665		$	12,816
Net losses reclassified out of accumulated other comprehensive income	1,358			122			2,218
Net gains in other comprehensive income	$	2,928		$	6,787		$	15,034

Investment in Debt Securities. As of December 31, 2011, the Company had a $2.0 million investment in an auction rate security maturing in 2044. The Company classifies this debt security as a trading security which is included in deferred charges and other assets on the Company’s consolidated balance sheets.

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 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, 2011 and 2010, 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, 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	$	—

Description of Securities	Fair Value as  of December 31, 2010		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	$	2,909	$	—	$	—	$	2,909
Available for sale:
U.S. Government Bonds	$	20,033	$	20,033	$	—	$	—
Federal Agency Mortgage Backed Securities	21,204		—		21,204		—
Municipal Bonds	32,541		—		32,541		—
Corporate Asset Backed Obligations	9,077		—		9,077		—
Subtotal, Debt Securities	82,855		20,033		62,822		—
Common Stock	68,016		68,016		—		—
Cash and Cash Equivalents	3,007		3,007		—		—
Total available for sale	$	153,878	$	91,056	$	62,822	$	—

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

	2011			2010
Balance at January 1	$	2,909		$	2,510
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)	(220		)	399
Balance at December 31	$	1,120		$	2,909

_____________________

(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, 2011 and 2010. 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, 2011 and 2010.

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Commitments, Contingencies and Uncertainties

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies Disclosure [Abstract]

Commitments, Contingencies And Uncertainties

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 July 2031	August 2011
Power Purchase Agreement	Sun Edison 1		12	MW	25 years after operational start date	2012
Power Purchase Agreement	Sun Edison 2		10	MW	25 years after operational start date	2012
Power Purchase Agreement	NextEra Energy Resources		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 NextEra Energy Resource 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 for two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which commercial operation is estimated to begin in 2012. 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

General. The Company is subject to laws and regulations with respect to air, soil and water quality, waste disposal and other environmental matters by federal, state, regional, tribal and local authorities. Those authorities govern facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these requirements can result in actions by regulatory agencies or other authorities 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 and regulations are subject to change and, as a result of those changes, 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”) 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. 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 from the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions starting in 2009. The U.S. Court of Appeals for the District of Columbia voided CAIR in 2008; however, the Company has complied with CAIR since 2009, and such rule is binding. 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		62

Cross-State Air Pollution Rule. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which is intended to replace CAIR. CSAPR requires 28 states, including Texas, to further reduce power plant emissions of SO₂ and NOx. Under CSAPR, reductions in annual SO₂ and NOx emissions were required to begin January 1, 2012, with further reductions required beginning January 1, 2014. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued its ruling to stay CSAPR, including the supplemental final rule, pending judicial review, which delays CSAPR's implementation date beyond January 1, 2012. The court is scheduled to hear the cases against the rule in April 2012. Under this timeframe, the court could issue its decision by summer or early fall 2012. As the outcome of the judicial review and any other legal or Congressional challenges are uncertain, the Company is unable to determine what impact CSAPR may ultimately have on its operations and consolidated financial results, but it could be material. Until the legal challenges to CSAPR are resolved, the Company's obligations under CAIR remains in effect.

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, CO and SO₂. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. The Company is currently evaluating what impact this 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. In addition, the EPA is currently reviewing the PM NAAQS. The Company cannot at this time predict the impact of this review and any possible new standards on its operations or consolidated financial results, but it could be material. The EPA had been in the process of revising the NAAQS for ozone. However, in September 2011, President Obama ordered the EPA to withdraw its proposal. Work, however, is underway to support EPA's planned reconsideration of the standards in 2013.

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 power plants, which replaces the prior federal Clean Air Mercury Rule and requires significant reductions in emissions of mercury and other air toxics. Companies impacted by the new standards will have up to four (and in certain cases five) years to comply. The Company is currently evaluating the new standards and cannot at this time determine the impact they may have on its Four Corners plant, but the cost of compliance could be material.

Climate Change. 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 (“GHG”) emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of GHGs, such as carbon dioxide, could impose significant costs or limitations on the Company. In recent years, the U.S. Congress has considered new legislation to restrict or regulate GHG emissions, although federal efforts directed at enacting comprehensive climate change legislation stalled in 2010 and appear unlikely to recommence in the near future. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered by Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In September 2009, the EPA adopted a rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. GHG emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company's fossil fuel-fired power generating assets are subject to this rule, and the first report containing 2010 emissions was submitted to the EPA prior to the September 30, 2011 due date. The Company also has inventoried and implemented procedures for electrical equipment containing sodium hexafluoride ("SF6"), another GHG. The Company is tracking these GHG emissions pursuant to the EPA's new SF6 reporting rule that was finalized in late 2010 and became effective January 1, 2011. The first report to EPA under this rule was originally due on March 31, 2012, but in November 2011, EPA delayed its submittal to September 26, 2012.

The EPA has also proposed and finalized other rulemakings on GHG emissions that affect electric utilities. Under EPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications (referred to as the “PSD” program). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or 100,000 tons per year, depending on various factors), will be required to implement “best available control technology,” or “BACT”. Pursuant to the rule, the EPA may reduce the 75,000 tons threshold referenced above in 2012 or thereafter. The EPA has issued guidance on what BACT entails for the control of GHGs, and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of these new regulations on the Company's operations cannot be determined at this time, but the cost of compliance with new regulations could be material. Also, on December 23, 2010, the EPA announced a settlement agreement with states and environmental groups regarding setting new source performance standards for GHG emissions from new and existing coal-, gas- and oil-based power plants. Pursuant to this agreement, and certain agreed upon extensions, the EPA intends to issue proposed rules for new and modified electric generating units ("EGUs") in 2012. It is unclear when the EPA will propose a GHG New Source Performance Standard ("NSPS") for existing EGUs and how stringent it would be, but this rule is expected. The impact of these rules on the Company is unknown at this time, but they could result in significant costs.

In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to consider how to address GHG emissions and are actively considering the development of emission inventories or regional GHG cap and trade programs.

It is not currently possible to predict with confidence how any pending, proposed or future GHG legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact the Company's business. However, any such legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or reduced demand for the power the Company generates, could require the Company to purchase rights to emit GHG, and 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 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. Substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. 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 at present to meaningfully quantify the costs of these potential impacts.

Contamination Matters. The Company has a provision for environmental remediation obligations of approximately $0.3 million at December 31, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):

	Years Ended December 31,
	2011			2010		2009
Clean Air Act (1)	$	716	—	$	615	$	810
Clean Water Act (2)	264			178		597

________________

(1)Includes $0.3 million related to alleged excess emissions at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009.

(2)2011 excludes a reduction of approximately $0.1 million related to an adjustment for estimated remediation costs for Copper generating station. 2009 also excludes a reduction of $0.6 million related to an adjustment for estimated remediation costs for a property previously owned by the Company.

The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community reservation in Arizona and designated it as a Superfund site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has an agreement with the EPA and a former property owner to resolve this matter and on June 30, 2011, the Company entered into a consent decree with the EPA at a cost to the Company of less than $0.1 million.

Environmental Litigation and Investigations. On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the New Source Review provisions of the CAA. APS responded to this request in 2009. The Company is unable to predict the timing or content of the EPA's response, if any, or any resulting actions.

The Company received word 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 provisions of the CAA. Subsequent to filing its original Complaint, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's 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 NSPS. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. APS advised that it believes the claims in this matter are without merit and will vigorously defend against them. The Company is unable to predict the outcome of these alleged violations.

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 and parking facilities 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 $1.1 million for 2011, 2010 and 2009. As of December 31, 2011, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2012	$	1,030
2013	951
2014	919
2015	477
2016	438

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Employee Benefits (Defined Benefit Plan, Amounts Recognized in Balance Sheet) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current liabilities	$ 0	$ 0
Noncurrent liabilities	(104,924)	(71,377)
Total liabilities	(104,924)	(71,377)
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current liabilities	(1,844)	(1,914)
Noncurrent liabilities	(24,703)	(22,094)
Total liabilities	$ (26,547)	$ (24,008)

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Common Stock (Notes)

12 Months Ended

Dec. 31, 2011

Common Stock [Abstract]

Shareholders' Equity and Share-based Payments , Including Earnings Per Share Information

Common Stock

Overview

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

Long-Term Incentive Plan

On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the “2007 LTIP”) and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options 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 2011:

	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, 2010	101,246	$	12.82
Options exercised	53,910	12.83					$	692	$	327
Options outstanding at December 31, 2011	47,336	12.80		0.99	$	1,034
Exercisable at December 31, 2011	47,336	12.80		0.99	1,034

The intrinsic value of stock options exercised in 2011, 2010 and 2009 were $1.0 million, $1.3 million and $1.5 million, respectively. No options were forfeited, vested or expired during 2011 and 2010.

All stock options outstanding have vested. No compensation cost was recognized in 2009, 2010 and 2011 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 2011, 2010 and 2009 is presented below (in thousands):

	2011			2010			2009
Expense	$	2,258		$	1,589		$	1,537
Deferred tax benefit	790			556			538
Current tax expense (benefit) recognized (a)	(518		)	(169		)	134

_____________________

(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 2011, 2010 and 2009 is presented below (in thousands):

	2011		2010		2009
Aggregated intrinsic value	$	3,279	$	1,749	$	1,331
Fair value at grant date	1,799		1,265		1,714

The unvested restricted stock transactions for 2011 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, 2010	143,371		$	18.30
Restricted stock awards	118,110		28.98
Lapsed restrictions and vesting	(103,096	)	17.45
Forfeitures	(2,200	)	23.20
Restricted shares outstanding at December 31, 2011	156,185		26.87		$	2,136	$	5,410

_______________________

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

The weighted average fair values per share at grant date for restricted stock awarded during 2011, 2010 and 2009 were:

	2011		2010		2009
Weighted average fair value per share	$	28.98	$	20.03	$	14.59

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		Compensation Costs Expensed Period	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
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
January 1, 2010	30.0	%	9,525	662		2007-2009	193

In 2012, 2013 and 2014, 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 174,038 shares that vested on January 1, 2012, the actual number of shares to be issued can range from zero to 392,328 shares.

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

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

	Number Outstanding		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a) (in thousands)		Aggregate Intrinsic Value (in thousands)
Performance shares outstanding at December 31, 2010	219,800		$	15.86
Performance share awards	112,164		23.45
Performance shares vested	(36,350	)	17.27
Performance shares lapsed	—		—
Performance shares forfeited	—		—
Performance shares outstanding at December 31, 2011	295,614		18.57		$	1,825	$	10,240

_______________________

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

A summary of information related to performance shares for 2011, 2010 and 2009 is presented below:

	2011		2010		2009
Weighted average per share grant date fair value per share of performance shares awarded	$	23.45	$	19.82	$	12.00
Fair value of performance shares vested (in thousands)	628		663		—
Intrinsic value of performance shares vested (in thousands)	1,032		193		—
Compensation expense (in thousands) (a)	1,573		988		727
Deferred tax expense related to compensation expense (in thousands)	551		346		254

_____________________

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

Repurchase Program

Detail regarding the Company's stock repurchase program are presented below:

	Since 1999 (a)		Twelve Months Ended December 31,		Authorized Shares
Shares repurchased	25,406,184		2,782,455
Cost, including commission (in thousands)	$	423,647	$	86,508
2010 Plan balance at December 31, 2010					676,271
2011 Plan repurchase shares authorized (b)					2,500,000
Total remaining shares available for repurchase at December 31, 2011					393,816

______________________

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

(b) On March 21, 2011, the Board of Directors authorized an additional repurchase of the Company’s common stock (the “2011 Plan”).

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

Dividend Policy

On December 30, 2011, the Company paid $8.8 million of quarterly dividends to shareholders. The Company paid a total of $27.2 million in cash dividends during the twelve months ended December 31, 2011. On January 26, 2012, the Board of Directors declared a quarterly cash dividend of $0.22 per share payable on March 30, 2012 to shareholders of record on March 15, 2012.

Basic and Diluted Earnings Per Share

FASB guidance which 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,
	2011			2010			2009
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	41,349,883			43,129,735			44,524,146
Dilutive effect of unvested performance awards	206,658			101,780			27,876
Dilutive effect of stock options	30,518			62,904			43,045
Diluted number of common shares outstanding	41,587,059			43,294,419			44,595,067
Basic net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income allocated to participating restricted stock	(471		)	(403		)	(240		)
Net income available to common shareholders	$	103,068		$	100,200		$	66,693
Diluted net income per common share:
Net income	$	103,539		$	100,603		$	66,933
Income reallocated to participating restricted stock	(469		)	(401		)	(240		)
Net income available to common shareholders	$	103,070		$	100,202		$	66,693
Basic net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.83			2.32			1.50
Basic net income per common share	$	2.49		$	2.32		$	1.50
Diluted net income per common share:
Distributed earnings	$	0.66		$	—		$	—
Undistributed earnings	1.82			2.31			1.50
Diluted net income per common share	$	2.48		$	2.31		$	1.50

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,
	2011	2010	2009
Restricted stock awards	81,653	75,270	66,628
Performance shares (a)	—	24,225	161,842
Stock options	—	—	53,610

_____________________

(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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Common Stock (Vested Restricted Stock Aggregate Intrinsic Value And Grant Date Fair Value) (Details) (Restricted Stock, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate intrinsic value	$ 3,279	$ 1,749	$ 1,331
Fair value at grant date	$ 1,799	$ 1,265	$ 1,714

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Financial Instruments And Investments (Long-Term Debt And Short-Term Borrowings - Narratives) (Details) (USD $)	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2011 Nuclear Fuel Financing	Dec. 31, 2011 Working Capital and General Purpose	Aug. 18, 2010 RGRT Senior Notes	Dec. 31, 2011 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035	Dec. 31, 2010 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035	May 01, 2005 Senior Notes 6.00% Senior Notes, Net of Discount, due 2035
Financial Instruments and Investments [Line Items]
Debt Instrument, Face Amount					$ 110,000,000			$ 400,000,000
Line of Credit Facility, Amount Outstanding			13,400,000	20,000,000
Debt Instrument, Interest Rate, Stated Percentage						6.00%	6.00%	6.00%
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	400,000
Decommissioning Fund Investments	$ 167,963,000	$ 153,878,000

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

12 Months Ended

Dec. 31, 2011

Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant [Abstract]

Schedule of Public Utility Property, Plant, and Equipment

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, 2011 (in thousands):

	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	768,284	$	(240,862	)	$	527,422
Steam and other	557,286		(223,109		)	334,177
Total production	1,325,570		(463,971		)	861,599
Transmission	394,385		(238,940		)	155,445
Distribution	864,746		(308,644		)	556,102
General	141,921		(78,323		)	63,598
Intangible	63,151		(31,775		)	31,376
Total	$	2,789,773	$	(1,121,653	)	$	1,668,120

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):

2009	$	4,542
2010	6,312
2011	6,668
2012 (estimated)	6,124
2013 (estimated)	5,403
2014 (estimated)	4,292
2015 (estimated)	3,542
2016 (estimated)	3,045

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, 2011 and 2010 is as follows (in thousands):

	December 31, 2011						December 31, 2010
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	768,284		$	211,983		$	772,710		$	209,427
Accumulated depreciation	(240,862		)	(164,622		)	(225,461		)	(159,679		)
Construction work in progress	53,822			1,634			48,703			1,940
Total	$	581,244		$	48,995		$	595,952		$	51,688

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 will now expire in 2045, 2046 and 2047, respectively. For the last three quarters of 2011 combined, the extension of the operating licenses 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. The Company is required to maintain a minimum accumulation and a minimum 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, 2011, the Company’s decommissioning trust fund had a balance of $168.0 million, and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.

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 increase in the license life 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 will lower annual expenses in the future. 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. See “Spent Fuel Storage” and “Disposal of Low-Level Radioactive Waste” below.

Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the on-site facilities until accepted by the DOE for permanent disposal. The 2010 Study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2057. APS believes 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.

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 has previously reported that its spent nuclear fuel disposal facilities would not be in operation in the near future. In November 1997, the United States Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. The Company cannot predict when spent fuel shipments to the DOE will commence.

The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde that 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.

In December 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. APS pursued a damages claim for costs incurred through December 2006 in a trial that began on January 28, 2009. On June 18, 2010, the court awarded APS and the other Palo Verde Participants approximately $30 million. 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. APS is continuing to pursue settlement of damage claims for costs incurred after 2006.

Disposal of Low-level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. The construction and opening of low-level radioactive waste disposal sites have been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed sites. The opposition, delays, uncertainty and costs that have been experienced demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.

Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. On March 11, 2011, a 9.0 magnitude earthquake occurred off the northeastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant's required licensing and design parameters. Validation of that data will continue as more information becomes available.

Following the March 11, 2011 earthquake and tsunami in Japan, the NRC launched a two-pronged review of U.S. nuclear power plant safety. The NRC supported the establishment of an agency task force to conduct both a near- and long-term analysis of the lessons that can be learned from the situation in Japan. The near-term task force issued a report on July 12, 2011, and on October 3, 2011, the NRC staff issued a plan for implementing the near-term task force's recommendations.

On October 18, 2011, the NRC Commissioners directed the NRC staff to implement, without delay, the near-term task force recommendations, subject to certain conditions. One such condition is that the agency should strive to complete and implement lessons learned from the earthquake and tsunami in Japan within five years. A second condition is that the staff should designate the recommendation for a rulemaking to address extended loss of offsite power to be completed within 24 to 30 months.

Until further action is taken by the NRC as a result of this event, the Company cannot predict any 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 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 $2.75 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 $9.57 million for the current policy period.

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Accounting for Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Accounting for Asset Retirement Obligations

Asset Retirement Obligation Disclosure

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

The 2011 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, 2011 is $168.0 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 ARO liability and the revised 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 due to Palo Verde license extension.

	2011			2010			2009
ARO liability at beginning of year	$	92,911		$	85,358		$	78,037
Liabilities incurred	—			—			—
Liabilities settled	(793		)	(85		)	—
Revisions to estimate	(41,670		)	(377		)	—
Accretion expense	5,692			8,015			7,321
ARO liability at end of year	$	56,140		$	92,911		$	85,358

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.

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Accumulated Other Comprehensive Income (Loss)

12 Months Ended

Dec. 31, 2011

Accumulated Other Comprehensive Income (Loss) [Abstract]

Accumulated Other Comprehensive Income (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, 2008	$	(6,159	)	$	(9,834	)	$	(13,371	)	$	(29,364	)
Other comprehensive income (loss)	15,034			(49,709		)	317			(34,358		)
Income tax benefit (expense)	(3,007		)	16,957			(115		)	13,835
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	)

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Common Stock (Outstanding Performance Share Awards) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years		Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares lapsed, Number Outstanding	0
Performance shares lapsed, Weighted Average Grant Date Fair Value	$ 0.00
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares Payout Level	100.00%
Share based compensation, outstanding at beginning of period (in shares)	219,800
Performance shares awards, Number Outstanding	112,164
Performance shares vested, Number Outstanding	(36,350)
Performance shares forfeited, Number Outstanding	0
Share based compensation, outstanding at end of period (in shares)	295,614		219,800
Performance shares outstanding, Weighted Average Grant Date Fair Value, Beginning of Period	$ 15.86
Performance shares awards, Weighted Average Grant Date Fair Value	$ 23.45		$ 19.82	$ 12.00
Performance shares vested, Weighted Average Grant Date Fair Value	$ 17.27
Performance shares forfeited, Weighted Average Grant Date Fair Value	$ 0.00
Performance shares outstanding, Weighted Average Grant Date Fair Value, End of Period	$ 18.57		$ 15.86
Performance shares outstanding, Unrecognized Compensation Expense	$ 1,825	[1]
Performance shares outstanding, Aggregate Intrinsic Value	$ 10,240
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	1

[1] The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year.

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Employee Benefits (Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Projected benefit obligation	$ (296,293)	$ (242,718)
Accumulated benefit obligation	(250,753)	(205,167)
Fair value of plan assets	191,369	171,341
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Projected benefit obligation	(26,547)	(24,008)
Accumulated benefit obligation	(26,547)	(23,538)
Fair value of plan assets	$ 0	$ 0

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Common Stock (Common Stock Repurchase Program) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended				156 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Repurchase of Equity	Dec. 31, 2011 Repurchase of Equity		Mar. 21, 2011 Repurchase of Equity		Dec. 31, 2010 Repurchase of Equity
Repurchase of Equity [Line Items]
Shares repurchased				2,782,455	25,406,184	[1]
Cost, including commission	$ 87,008	$ 33,726	$ 24,105	$ 86,508	$ 423,647	[1]
2010 Plan balance at December 31, 2010									676,271
2011 Plan repurchase shares authorized							2,500,000	[2]
Total remaining shares available for repurchase at December 31, 2011				393,816	393,816

[1] Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

[2] On March 21, 2011, the Board of Directors authorized an additional repurchase of the Company’s common stock (the “2011 Plan”).

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Employee Benefits (Recognized Net Periodic Benefit Costs and Other Comprehensive Income -Other Postretirement Benefit Plans) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Total recognized in net periodic benefit cost and other comprehensive income	$ 41,061,000	$ (22,704,000)	$ 6,545,000
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	5,900,000
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), Net Gains (Losses), In the Next Fiscal Year	$ 600,000

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Common Stock (Performance Shares) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
The Number of Simulations on Fair Value of Average Payout	1,000,000
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Compensation Costs Expensed	$ 1,573	[1]	$ 988	[1]	$ 727	[1]
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	3 years
Share Based Compensation By Share Based Payment Award, Valuation Model Performance Period	3 years
Performance Shares Payout Level	100.00%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Performance Shares Awarded	0
Performance Shares Payout Level	0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Performance Shares Awarded	392,328
Performance Shares Payout Level	200.00%
January 1, 2012 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	175.00%
Performance shares vested - Performance Shares Awarded	174,038
Performance shares vested - Compensation Costs Expensed	1,193
Performance shares vested - Aggregated Intrinsic Value	6,029
July 9, 2011 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	112.50%
Performance shares vested - Performance Shares Awarded	2,250
Performance shares vested - Compensation Costs Expensed	23
Performance shares vested - Aggregated Intrinsic Value	75
September 3, 2011 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	112.50%
Performance shares vested - Performance Shares Awarded	3,825
Performance shares vested - Compensation Costs Expensed	40
Performance shares vested - Aggregated Intrinsic Value	129
January 1, 2011 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	112.50%
Performance shares vested - Performance Shares Awarded	34,820
Performance shares vested - Compensation Costs Expensed	565
Performance shares vested - Aggregated Intrinsic Value	959
January 1, 2010 | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares vested - Payout Ratio	30.00%
Performance shares vested - Performance Shares Awarded	9,525
Performance shares vested - Compensation Costs Expensed	662
Performance shares vested - Aggregated Intrinsic Value	$ 193

[1] Includes cumulative adjustments for forfeiture of performance share awards by certain executives.

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Employee Benefits (Weighted Average Assumptions Used to Calculate Net Period Benefit Costs- Retirement Plans) (Details)	12 Months Ended	0 Months Ended	12 Months Ended
	Dec. 31, 2011 Retirement Plans	Jan. 03, 2011 Retirement Income Plan	Dec. 31, 2011 Net Periodic Benefit Costs Retirement Income Plan	Dec. 31, 2010 Net Periodic Benefit Costs Retirement Income Plan	Dec. 31, 2009 Net Periodic Benefit Costs Retirement Income Plan	Dec. 31, 2011 Net Periodic Benefit Costs Supplement Retirement Plan	Dec. 31, 2010 Net Periodic Benefit Costs Supplement Retirement Plan	Dec. 31, 2009 Net Periodic Benefit Costs Supplement Retirement Plan	Dec. 31, 2011 Net Periodic Benefit Costs Excess Benefit Plan	Dec. 31, 2010 Net Periodic Benefit Costs Excess Benefit Plan	Dec. 31, 2009 Net Periodic Benefit Costs Excess Benefit Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Discount rate			5.40%	5.90%	6.10%	4.60%	5.20%	6.30%	5.30%	6.00%	6.30%
Expected long-term return on plan assets		7.50%	7.50%	7.50%	8.50%
Rate of compensation increase	15.80%		5.00%	5.00%	5.00%				5.00%	5.00%	5.00%

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Long-Term Debt and Financing Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt and Financing Obligations [Abstract]

Schedule of Debt

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

	December 31,
	2011			2010
	(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
4.80% 2005 Series A refunding bonds, due 2040 (5.32% 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
4.00% 2002 Series A refunding bonds, due 2032 (5.07% 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)	397,894			397,856
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,768			148,754
Total Senior Notes	546,662			546,610
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	849,797			849,745
Financing Obligations:
Revolving Credit Facility ($33,379 due in 2012) (4)	33,379			4,704
Total long-term debt and financing obligations	883,176			854,449
Current Portion (amount due within one year):
Current maturities of long-term debt	(33,300		)	—
Short-term borrowings under the revolving credit facility	(33,379		)	(4,704		)
	$	816,497		$	849,745

 _____________________

(1) Pollution Control Bonds (“PCBs”)

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 4.00% 2002 Series A must be remarketed in August 2012 and is shown as current maturities of long-term debt on the Company's 2011 balance sheet.

(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.

(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 2011.

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

Prior to November 15, 2011, the Company had available a $200 million credit facility with a four-year term ending September 2014. The credit facility provided for the financing of nuclear fuel, which was accomplished through the RGRT that borrowed under the facility to acquire and process nuclear fuel. The Company was obligated to repay the RGRT’s borrowings with interest. Any amounts not borrowed by the RGRT could have been borrowed by the Company for working capital needs.

On November 15, 2011, the Company and RGRT entered into an amended and restated 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. Under the terms of the RCF, the Company and RGRT have available $200 million of credit for a term ending September 23, 2016. The Company may request that the RCF be increased up to a total of $300 million during the term of the RCF, subject to lender approval.

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 2011. As of December 31, 2011, the total amount borrowed by RGRT was $13.4 million for nuclear fuel under the RCF, and $20.0 million was 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, 2011.

Schedule of Maturities of Long-term Debt

As of December 31, 2011, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):

2012	$	33,300
2013	—
2014	—
2015	15,000
2016	—

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Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant (Amortization of Intangible Plant Assets - Software) (Details) (Intangible Plant Software, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009
Intangible Plant Software
Property, Plant and Equipment and Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Amortization Expense	$ 6,668	$ 6,312	$ 4,542
Future Amortization Expense, 2012 (estimated)	6,124
Future Amortization Expense, 2013 (estimated)	5,403
Future Amortization Expense, 2014 (estimated)	4,292
Future Amortization Expense, 2015 (estimated)	3,542
Future Amortization Expense, 2016 (estimated)	$ 3,045
Finite-Lived Intangible Assets, Useful Life, Minimum	5
Finite-Lived Intangible Assets, Useful Life, Maximum	10

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Employee Benefits

12 Months Ended

Dec. 31, 2011

Employee Benefits [Abstract]

Pension and Other Postretirement Benefits Disclosure

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,
	2011						2010
	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	$	242,718		$	24,008		$	215,944		$	21,767
Service cost	6,590			260			5,888			176
Interest cost	12,871			1,116			12,507			1,122
Amendments	—			—			—			838
Actuarial loss	42,508			2,980			16,008			1,822
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Benefit obligation at end of year	296,293			26,547			242,718			24,008
Change in plan assets:
Fair value of plan assets at end of prior year	171,341			—			155,140			—
Actual return on plan assets	16,422			—			17,030			—
Employer contribution	12,000			1,817			6,800			1,717
Benefits paid	(8,394		)	(1,817		)	(7,629		)	(1,717		)
Fair value of plan assets at end of year	191,369			—			171,341			—
Funded status at end of year	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(1,844	)	$	—		$	(1,914	)
Noncurrent liabilities	(104,924		)	(24,703		)	(71,377		)	(22,094		)
Total	$	(104,924	)	$	(26,547	)	$	(71,377	)	$	(24,008	)

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

	December 31,
	2011						2010
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(296,293	)	$	(26,547	)	$	(242,718	)	$	(24,008	)
Accumulated benefit obligation	(250,753		)	(26,547		)	(205,167		)	(23,538		)
Fair value of plan assets	191,369			—			171,341			—

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

	Years Ended December 31,
	2011				2010
	Retirement Income Plan		Non-Qualified Retirement Plans		Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	129,820	$	8,990	$	95,828	$	6,364
Prior service cost	24		408		46		502
Total	$	129,844	$	9,398	$	95,874	$	6,866

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

	December 31,
	2011						2010
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.3	%	3.6	%	4.1	%	5.4	%	4.6	%	5.3	%
Rate of compensation increase	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 changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. A 1% increase in the discount rate would decrease the December 31, 2011 retirement plans' projected benefit obligation by 12.7%. A 1% decrease in the discount rate would increase the December 31, 2011 retirement plans' projected benefit obligation by 15.8%.

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

	Years Ended December 31,
	2011					2010					2009
	Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	6,590		$	260	$	5,888		$	176	$	5,414		$	120
Interest cost	12,871			1,116		12,507			1,122		11,942			1,241
Amendments	—			—		—			838		—			—
Expected return on plan assets	(14,095		)	—		(13,867		)	—		(15,439		)	—
Amortization of:
Net loss	6,190			354		3,331			218		1,549			76
Prior service cost	21			94		21			94		21			94
Net periodic benefit cost	$	11,577		$	1,824	$	7,880		$	2,448	$	3,487		$	1,531

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

	Years Ended December 31,
	2011						2010						2009
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	40,181		$	2,980		$	12,844		$	1,822		$	48,531		$	1,892
Amortization of:
Net loss	(6,190		)	(354		)	(3,331		)	(218		)	(1,549		)	(76		)
Prior service cost	(21		)	(94		)	(21		)	(94		)	(21		)	(94		)
Total expense recognized in other comprehensive income	$	33,970		$	2,532		$	9,492		$	1,510		$	46,961		$	1,722

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

	Years Ended December 31,
	2011				2010				2009
	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	$	45,547	$	4,356	$	17,372	$	3,958	$	50,448	$	3,253

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2012 (in thousands):

	Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	11,300	$	560
Prior service cost	20		90

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

	2011						2010						2009
			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	5.4	%	4.6	%	5.3	%	5.9	%	5.2	%	6.0	%	6.1	%	6.3	%	6.3	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		8.5	%	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 changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan.

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2011, 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, 2011
Equity securities	50	%
Fixed income	45	%
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 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.

The fair value of the Company’s Retirement Plan assets at December 31, 2011 and 2010, 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, 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

Description of Securities	Fair Value as of December 31, 2010		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	$	4,975	$	4,975	$	—	$	—
U.S. Treasury Securities	83,601		83,601		—		—
Guaranteed Investment Contract	550		—		550		—
Common Stock	54,957		54,957		—		—
Mutual Funds	19,501		19,501		—		—
Limited Partnership Interest in Real Estate (a)	7,757		—		—		7,757
Total Plan Investments	$	171,341	$	163,034	$	550	$	7,757

 _____________________

(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, 2009	$	8,288
Unrealized loss in fair value	(531		)
Balance at December 31, 2010	7,757
Sale of land	(102		)
Unrealized gain in fair value	856
Balance at December 31, 2011	$	8,511

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, 2011 and 2010.

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 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 $19.8 million to its retirement plans in 2012.

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
2012	$	9,132	$	1,844
2013	9,967		1,813
2014	10,932		1,777
2015	11,924		1,758
2016	13,021		1,801
2017-2021	83,027		9,430

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 currently based on the funding amounts established in PUCT Docket No. 37690. 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.

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,
	2011			2010
Change in benefit obligation:
Benefit obligation at end of prior year	$	95,254		$	118,267
Service cost	2,988			3,558
Interest cost	5,379			6,664
Actuarial loss	32,694			(3,807		)
Amendments (a)	—			(26,605		)
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Benefit obligation at end of year	133,272			95,254
Change in plan assets:
Fair value of plan assets at end of prior year	33,660			29,348
Actual return on plan assets	—			2,514
Employer contribution	2,200			4,621
Benefits paid	(4,180		)	(3,598		)
Retiree contributions	941			584
Medicare Part D subsidy	196			191
Fair value of plan assets at end of year	32,817			33,660
Funded status (b)	$	(100,455	)	$	(61,594	)

_____________________

(a) The amendments that occurred during the twelve months ended December 31, 2010 primarily related to modifications to the required copayment levels, deductibles and out-of-pocket maximum responsibilities retained by the retired employees.

(b) 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,
	2011			2010
Net loss (gain)	$	20,144		$	(14,411	)
Prior service credit	(30,647		)	(36,574		)
	$	(10,503	)	$	(50,985	)

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

	December 31,
	2011		2010
Discount rate at end of year	4.3	%	5.5	%
Health care cost trend rates:
Initial	8.0	%	8.5	%
Ultimate	5.0	%	5.0	%
Year ultimate reached	2026		2018

The discount rate is changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. A 1% increase in the discount rate would decrease the December 31, 2011 accumulated postretirement benefit obligation by 14.1%. A 1% decrease in the discount rate would increase the December 31, 2011 accumulated postretirement benefit obligation by 17.9%.

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

	Years Ended December 31,
	2011			2010			2009
Service cost	$	2,988		$	3,558		$	3,395
Interest cost	5,379			6,664			6,492
Expected return on plan assets	(1,823		)	(1,529		)	(1,499		)
Amortization of:
Prior service benefit	(5,927		)	(2,869		)	(2,869		)
Net gain	(39		)	(175		)	—
Net periodic benefit cost	$	578		$	5,649		$	5,519

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

	Years Ended December 31,
	2011		2010			2009
Net loss (gain)	$	34,517	$	(4,792	)	$	(1,843	)
Prior service benefit	—		(26,605		)	—
Amortization of:
Prior service benefit	5,927		2,869			2,869
Net gain	39		175			—
Total recognized in other comprehensive income	$	40,483	$	(28,353	)	$	1,026

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

	Years Ended December 31,
	2011		2010			2009
Total recognized in net periodic benefit cost and other comprehensive income	$	41,061	$	(22,704	)	$	6,545

The amounts in accumulated other comprehensive income that are expected to be recognized as a component of net periodic benefit cost during 2012 is a prior service benefit of $5.9 million and a net gain of $0.6 million.

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

	2011		2010		2009
Discount rate at beginning of year	5.5	%	5.9	%	6.0	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.9	%
Health care cost trend rates:
Initial	8.5	%	8.5	%	9.0	%
Ultimate	5.0	%	5.0	%	5.0	%
Year ultimate reached	2018		2017		2017

The discount rate is changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan.

For measurement purposes, an 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease gradually to 5% for 2018 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, 2011 benefit obligation by $22.8 million or $18.3 million, respectively. In addition, such a 1% change would increase or decrease the aggregate 2011 service and interest cost components of the net periodic benefit cost by $1.6 million or $1.2 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2011. 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, 2011
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 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.

The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2011 and 2010, 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, 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
Description of Securities	Fair Value as of December 31, 2010		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	$	4,122	$	4,122	$	—	$	—
Municipal Securities – Tax Exempt	11,348		—		11,348		—
Common Stock	16,735		16,735		—		—
Limited Partnership Interest in Real Estate (a)	1,455		—		—		1,455
Total Plan Investments	$	33,660	$	20,857	$	11,348	$	1,455

 ___________________

(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 the investments in real estate during the period (in thousands):

	Fair Value of Investments  in Real Estate
Balance at December 31, 2009	$	1,554
Unrealized loss in fair value	(99		)
Balance at December 31, 2010	1,455
Sale of land	(19		)
Unrealized gain in fair value	160
Balance at December 31, 2011	$	1,596

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, 2011 and 2010.

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 mutual 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.

The Company expects to contribute $2.5 million to its other postretirement benefits plan in 2012. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

2012	$	3,519
2013	4,006
2014	4,507
2015	5,058
2016	5,614
2017-2021	35,367

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 2011, 2010 and 2009 were $1.7 million, $1.7 million, and $1.6 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. 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. In 2009, the Company reached the required levels of earnings per share, customer satisfaction, and safety goals for an incentive payment of $8.6 million, respectively. The Company has renewed the Incentive Plan in 2012 with similar goals.

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Financial Instruments And Investments (Company's Decommissioning Trust Funds And Investments In Debt Securities) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	$ 167,963	$ 153,878
U.S. Government Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	12,776	20,033
Collateralized Mortgage Backed Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	26,825	21,204
Municipal Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	37,316	32,541
Corporate Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	12,400	9,077
Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	89,317	82,855
Equity Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	74,907	68,016
Cash and Cash Equivalents | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	3,739	3,007
Debt Securities
Financial Instruments and Investments [Line Items]
Investments in Debt Securities	1,120	2,909	2,510
Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Investments in Debt Securities		2,909
Quoted Prices In Active Markets For Identical Assets (Level 1) | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	91,422	91,056
Quoted Prices In Active Markets For Identical Assets (Level 1) | U.S. Government Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	12,776	20,033
Quoted Prices In Active Markets For Identical Assets (Level 1) | Collateralized Mortgage Backed Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Quoted Prices In Active Markets For Identical Assets (Level 1) | Municipal Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Quoted Prices In Active Markets For Identical Assets (Level 1) | Corporate Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Quoted Prices In Active Markets For Identical Assets (Level 1) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	12,776	20,033
Quoted Prices In Active Markets For Identical Assets (Level 1) | Equity Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	74,907	68,016
Quoted Prices In Active Markets For Identical Assets (Level 1) | Cash and Cash Equivalents | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	3,739	3,007
Quoted Prices In Active Markets For Identical Assets (Level 1) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Investments in Debt Securities	0	0
Significant Other Observable Inputs (Level 2) | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	76,541	62,822
Significant Other Observable Inputs (Level 2) | U.S. Government Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Other Observable Inputs (Level 2) | Collateralized Mortgage Backed Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	26,825	21,204
Significant Other Observable Inputs (Level 2) | Municipal Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	37,316	32,541
Significant Other Observable Inputs (Level 2) | Corporate Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	12,400	9,077
Significant Other Observable Inputs (Level 2) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	76,541	62,822
Significant Other Observable Inputs (Level 2) | Equity Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Other Observable Inputs (Level 2) | Cash and Cash Equivalents | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Other Observable Inputs (Level 2) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Investments in Debt Securities	0	0
Significant Unobservable Inputs (Level 3) | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | U.S. Government Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Collateralized Mortgage Backed Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Municipal Bonds | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Corporate Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Equity Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Cash and Cash Equivalents | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Available-for-sale Securities, Fair Value Disclosure	0	0
Significant Unobservable Inputs (Level 3) | Debt Securities | Decommissioning Fund Investments [Member]
Financial Instruments and Investments [Line Items]
Investments in Debt Securities	$ 1,120	$ 2,909

XML

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Principles of Consolidation

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

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, Policy [Policy Text Block]

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

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

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 regulartory asset will be amortized over the remaining life of the Company's 6% Senior Notes due in 2035.

Comprehensive Income

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. 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 2011, 2010 and 2009 was 2.80%, 3.21%, and 3.22%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note E.

Impairment of Long-Lived Assets

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

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 rate used in 2011 was 8.54% . The AFUDC rate utilized for the first six months of 2010 was 9.01% and 8.47% thereafter. The AFUDC rate utilized in 2009 was 8.94%.

Asset Retirement Obligation

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

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

Investments

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 income (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

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. 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

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 an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $19.6 million and $16.6 million at December 31, 2011 and 2010, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Allowance for Doubtful Accounts

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 2011, 2010 and 2009 are as follows (in thousands):

	2011		2010		2009
Balance at beginning of year	$	2,885	$	1,191	$	3,123
Additions:
Charged to costs and expense	6,209		4,756		3,289
Recovery of previous write-offs	2,034		852		1,316
Uncollectible receivables written off	8,113		3,914		6,537
Balance at end of year	$	3,015	$	2,885	$	1,191

Income Taxes

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. 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

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

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.

Reclassifications

Reclassification. Certain amounts in the consolidated financial statements for 2010 and 2009 have been reclassified to conform with the 2011 presentation.

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Employee Benefits (Fair Value Change in Investment in Real Estate) (Details) (Retirement Plans, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of year	$ 191,369		$ 171,341
Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year	7,757	[1]	8,288
Sale of land	(102)
Unrealized gain in fair value	856		(531)
Fair value of plan assets at end of year	$ 8,511	[1]	$ 7,757	[1]

[1] 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.

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Regulatory Assets and Liabilities Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	84 Months Ended
	Dec. 31, 2011		Dec. 31, 2010
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	$ 101,027		$ 88,557
Total regulatory liabilities	21,049		14,489
Amortization Period of Weighted Cost of Debt	30 years
Regulatory tax assets or liabilities
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	16,138	[1],[2]	9,326	[1],[2]
Accumulated Deferred Investment Tax Credit
Regulatory Assets and Liabilities [Line Items]
Total regulatory liabilities	4,911	[1],[3]	5,163	[1],[3]
Regulatory tax assets or liabilities
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	52,281	[1],[2]	37,230	[1],[2]
Loss on reacquired debt
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	20,044	[4]	20,897	[4]
Final coal reclamation
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	6,655	[2]	10,282	[2]
Nuclear fuel postload daily financing charge
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	3,470	[5]	2,007	[5]
Unrecovered issuance costs due to reissuance of PCBs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	578	[4]	599	[4]
Texas energy efficiency
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	4,497	[6]	5,460	[6]
Texas 2009 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	1,146	[7]	3,298	[7]
Texas 2012 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	648	[8]	0	[8]
Texas military base discount and recovery factor
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	2,526	[9]	761	[9]
New Mexico 2009 rate case procurement plan costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	0	[7]	232	[7]
New Mexico procurement plan costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	139	[8]	122	[8]
New Mexico 2009 rate case renewable energy credits
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	0	[7]	1,139	[7]
New Mexico renewable energy credits
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	2,884	[8]	930	[8]
New Mexico 2009 rate case costs
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	253	[7]	506	[7]
New Mexico 2010 FPPCAC audit
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	427	[8]	0	[8]
New Mexico Palo Verde deferred depreciation
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	5,176	[1]	4,773	[1]
New Mexico energy efficiency
Regulatory Assets and Liabilities [Line Items]
Total regulatory assets	$ 303	[6]	$ 321	[6]

[1] The amortization period for this asset is based upon the life of the associated assets.

[2] No specific return on investment is required since related assets and liabilities, including accumulated deferred income taxes and reclamation liability, offset.

[3] This item is excluded from rate base.

[4] This item is recovered as a component of the weighted cost of debt and amortized over 30 years beginning in 2005.

[5] This item is recovered through fuel recovery mechanisms.

[6] This asset is recovered through an annual recovery factor.

[7] This item is included in rate base which earns a return on investment.

[8] Amortization period is anticipated to be established in next general rate case.

[9] This item represents the net asset related to the military discount which is recovered from non-military customers through a recovery factor.

XML

Employee Benefits (Fair Value Measurements- Other Postretirement Benefits) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Dec. 31, 2010		Dec. 31, 2009
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 32,817		$ 33,660		$ 29,348
Restriction Period To Sell Partnership Interest Minimum	5 years
Restriction Period To Sell Partnership Interest Maximum	7 years
Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,000		4,122
Municipal Securities Tax Exempt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12,062		11,348
Common Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16,159		16,735
Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,596	[1]	1,455	[1]	1,554
Fair Value, Inputs, Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	19,159		20,857
Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,000		4,122
Fair Value, Inputs, Level 1 | Municipal Securities Tax Exempt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 1 | Common Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	16,159		16,735
Fair Value, Inputs, Level 1 | Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[1]	0	[1]
Fair Value, Inputs, Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12,062		11,348
Fair Value, Inputs, Level 2 | Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 2 | Municipal Securities Tax Exempt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	12,062		11,348
Fair Value, Inputs, Level 2 | Common Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 2 | Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[1]	0	[1]
Fair Value, Inputs, Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,596		1,455
Fair Value, Inputs, Level 3 | Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 3 | Municipal Securities Tax Exempt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 3 | Common Stock
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0
Fair Value, Inputs, Level 3 | Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 1,596	[1]	$ 1,455	[1]

[1] 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.

XML

Selected Quarterly Financial Data (Unaudited) Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Information

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.

	2011 Quarters								2010 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	191,663	$	307,633	$	242,605	$	176,112	$	181,344	$	280,342	$	211,397	$	204,168
Operating income	15,994		102,215		58,121		14,473		13,784		84,098		40,477		30,603
Income before extraordinary gain	5,453		58,321		32,990		6,775		7,466		49,896		21,507		11,449
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		10,286		—		—
Net income	5,453		58,321		32,990		6,775		7,466		60,182		21,507		11,449
Basic earnings per share:
Income before extraordinary gain	0.14		1.41		0.78		0.16		0.18		1.16		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.14		1.41		0.78		0.16		0.18		1.40		0.49		0.26
Diluted earnings per share:
Income before extraordinary gain	0.13		1.40		0.78		0.16		0.17		1.15		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.13		1.40		0.78		0.16		0.17		1.39		0.49		0.26
Dividends declared per share of common stock	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.

Schedule of Quarterly Financial Information

	2011 Quarters								2010 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	191,663	$	307,633	$	242,605	$	176,112	$	181,344	$	280,342	$	211,397	$	204,168
Operating income	15,994		102,215		58,121		14,473		13,784		84,098		40,477		30,603
Income before extraordinary gain	5,453		58,321		32,990		6,775		7,466		49,896		21,507		11,449
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		10,286		—		—
Net income	5,453		58,321		32,990		6,775		7,466		60,182		21,507		11,449
Basic earnings per share:
Income before extraordinary gain	0.14		1.41		0.78		0.16		0.18		1.16		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.14		1.41		0.78		0.16		0.18		1.40		0.49		0.26
Diluted earnings per share:
Income before extraordinary gain	0.13		1.40		0.78		0.16		0.17		1.15		0.49		0.26
Extraordinary gain related to Texas regulatory assets, net of tax	—		—		—		—		—		0.24		—		—
Net income	0.13		1.40		0.78		0.16		0.17		1.39		0.49		0.26
Dividends declared per share of common stock	0.22		0.22		0.22		—		—		—		—		—

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Employee Benefits (Expected Future Benefit Payments - Other Postretirement Benefit Plans) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $)	Dec. 31, 2011
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 2,500,000
2012	3,519,000
2013	4,006,000
2014	4,507,000
2015	5,058,000
2016	5,614,000
2017-2021	$ 35,367,000

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income	$ 103,539	$ 100,603	$ 66,933
Unrecognized pension and postretirement benefit costs:
Net loss arising during period	(77,678)	(9,874)	(48,580)
Prior service benefit	0	26,605	0
Reclassification adjustments included in net income for amortization of:
Prior service cost	(5,812)	(2,754)	(2,754)
Net (gain) loss	6,505	3,374	1,625
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period	1,570	6,665	12,816
Reclassification adjustments for net losses included in net income	1,358	122	2,218
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	361	338	317
Total other comprehensive income (loss) before income taxes	(73,696)	24,476	(34,358)
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs	30,134	(6,287)	16,957
Net unrealized gains (losses) on marketable securities	(563)	(1,357)	(3,007)
Losses on cash flow hedges	(203)	(122)	(115)
Total income tax benefit (expense)	29,368	(7,766)	13,835
Other comprehensive income (loss), net of tax	(44,328)	16,710	(20,523)
Comprehensive income	$ 59,211	$ 117,313	$ 46,410

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Employee Benefits (Net Periodic Benefit Costs) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Retirement Income Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 6,590	$ 5,888	$ 5,414
Interest cost	12,871	12,507	11,942
Amendments	0	0	0
Expected return on plan assets	(14,095)	(13,867)	(15,439)
Amortization of:
Net loss	6,190	3,331	1,549
Prior service cost	21	21	21
Net periodic benefit cost	11,577	7,880	3,487
Non-Qualified Retirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	260	176	120
Interest cost	1,116	1,122	1,241
Amendments	0	838	0
Expected return on plan assets	0	0	0
Amortization of:
Net loss	354	218	76
Prior service cost	94	94	94
Net periodic benefit cost	$ 1,824	$ 2,448	$ 1,531

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New Accounting Standards

12 Months Ended

Dec. 31, 2011

New Accounting Standards [Abstract]

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

New Accounting Standards

In June 2011, the FASB issued new guidance to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The new guidance requires an entity to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both presentations, an entity would have been required to present on the face of the financial statements reclassification adjustments for items that are reclassified from other comprehensive income to net income in the statement(s) where the components of net income and the components of other comprehensive income are presented. Historically, the Company has used the consecutive two-statement approach; however, this new guidance could require additional disclosure on the Company's statement of operations and related notes. In December 2011, the FASB issued new guidance to defer the effective date for amendments to the presentation of reclassification of items out of accumulated other comprehensive income. Deferring the effective date will allow the FASB time to redeliberate whether to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income for all periods presented. While the FASB is considering the operational concerns about the presentation requirements for reclassification adjustments and the needs of financial statement users for additional information about reclassification adjustments, the Company will continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before the guidance issued in June 2011 until further guidance becomes available.

In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include: (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires: (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. This guidance requires additional disclosure on fair value measurements but did not impact the Company's consolidated financial statements.

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Common Stock (Share-Based Compensation Options) (Details) (Stock Options, USD $)	12 Months Ended
	Dec. 31, 2011 years	Dec. 31, 2010	Dec. 31, 2009
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock options outstanding, beginning of period (in shares)	101,246
Stock options exercised (in shares)	53,910
Stock options outstanding, end of period (in shares)	47,336	101,246
Stock options, exercisable (in shares)	47,336
Weighted Average Exercise Price, beginning of period	$ 12.82
Weighted Average Exercise Price, options exercised	$ 12.83
Weighted Average Exercise Price, end of period	$ 12.80	$ 12.82
Weighted Average Exercise Price, exercisable	$ 12.80
Weighted Average Remaining Contractual Term, options outstanding (in years)	0.99
Weighted Average Remaining Contractual Term, exercisable (in years)	0.99
Aggregate Intrinsic Value, options outstanding	$ 1,034,000
Aggregate Intrinsic Value, exercisable	1,034,000
Cash received	692,000
Realized Current Tax Benefits	327,000
Intrinsic value of stock options exercised	$ 1,000,000	$ 1,300,000	$ 1,500,000

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Employee Benefits Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Short Term Incentive Plan Payout	$ 7.3	$ 7.4	$ 8.6
Defined Contribution Plans
Employee Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent	50.00%
Limits of Contribution Match of Employee Compensation, Percentage	6.00%
Defined Contribution Plan, Employer Contribution Amount	$ 1.7	$ 1.7	$ 1.6

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Employee Benefits (Changes in Fair Value Investment Real Estate - Other Postretirement Benefit Plans) (Details) (Other Postretirement Benefit Plans, Defined Benefit, USD $) In Thousands, unless otherwise specified				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Limited Partnership Interest in Real Estate		Dec. 31, 2010 Limited Partnership Interest in Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value of plan assets at end of prior year	$ 32,817	$ 33,660	$ 29,348	$ 1,455	[1]	$ 1,554
Unrealized loss in fair value				160		(99)
Sale of land				(19)
Fair value of plan assets at end of year	$ 32,817	$ 33,660	$ 29,348	$ 1,596	[1]	$ 1,455	[1]

[1] 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.

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Accumulated Other Comprehensive Income (Loss) (Schedule of Accumulated Other Comprehensive Income (Loss)) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net unrealized gains (losses) on marketable securities, beginning of period	$ 11,298	$ 5,868	$ (6,159)
Other comprehensive income (loss), net unrealized gains (losses) on marketable securities	2,928	6,787	15,034
Income tax beneift (expense), net unrealized gains (losses) on marketable securities	(563)	(1,357)	(3,007)
Net unrealized gains (losses) on marketable securities, end of period	13,663	11,298	5,868
Unrecognized pension and postretirement benefit cost, beginning of period	(31,522)	(42,586)	(9,834)
Other comprehensive income (loss), unrecognized pension and postretirement benefit costs	(76,985)	17,351	(49,709)
Income tax benefit (expense), unrecognized pension and postretirement benefit costs, tax	30,134	(6,287)	16,957
Unrecognized pension and postretirement benefit cost, end of period	(78,373)	(31,522)	(42,586)
Net losses on cash flow hedges, beginning of period	(12,953)	(13,169)	(13,371)
Other comprehensive income (loss), net losses on cash flow hedges	361	338	317
Income rax benefit (expense), net losses on cash flow hedges	(203)	(122)	(115)
Net losses on cash flow hedges, end of period	(12,795)	(12,953)	(13,169)
Accumulated other comprehensive income (loss), net of tax, beginning of period	(33,177)	(49,887)	(29,364)
Total other comprehensive income (loss), accumulated other comprehensive loss	(73,696)	24,476	(34,358)
Total income tax benefit (expense)	29,368	(7,766)	13,835
Accumulated other comprehensive income (loss), net of tax, end of period	$ (77,505)	$ (33,177)	$ (49,887)

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Allowance for Doubtful Accounts Receivable

Additions, deductions and balances for allowance for doubtful accounts for 2011, 2010 and 2009 are as follows (in thousands):

	2011		2010		2009
Balance at beginning of year	$	2,885	$	1,191	$	3,123
Additions:
Charged to costs and expense	6,209		4,756		3,289
Recovery of previous write-offs	2,034		852		1,316
Uncollectible receivables written off	8,113		3,914		6,537
Balance at end of year	$	3,015	$	2,885	$	1,191

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Financial Instruments And Investments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Level 1 to level 2 Transfers, Amount	$ 0	$ 0
Level 3 purchases, sales, issuances and settlements related to the assets	0	0
Auction Rate Securities [Member]
Trading Securities, Debt	$ 2,000,000

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Income Taxes (Recognized Income Tax Expense) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Federal
Current	$ 5,084	$ 19,251	$ (10,123)
Deferred	46,612	31,279	39,537
Total federal income tax	51,696	50,530	29,414
State:
Current	2,936	4,308	2,321
Deferred	(924)	1,947	1,309
Total state income tax	2,012	6,255	3,630
Total income tax expense	53,708	56,785	33,044
Tax expense classified as extraordinary gain	0	(5,769)	0
Total income tax expense before extraordinary item	$ 53,708	$ 51,016	$ 33,044

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Franchises and Significant Customers Franchises and Significant Customers (Tables)

12 Months Ended

Dec. 31, 2011

Franchises and Significant Customers [Abstract]

Schedule of Franchise Fee Agreements

The franchise agreements 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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Litigation

12 Months Ended

Dec. 31, 2011

Litigation [Abstract]

Legal Matters Disclosure

Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, 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 Note C and Note K for discussion of the effects of government legislation and regulation on the Company.

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Employee Benefits (Other Comprehensive Income, Other Postretirement Benefit Plans) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	$ (77,678)	$ (9,874)	$ (48,580)
Prior service benefit, arising during period	0	26,605	0
Net gain	(5,812)	(2,754)	(2,754)
Total recognized in other comprehensive income	(76,985)	17,351	(49,709)
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net loss (gain)	34,517	(4,792)	(1,843)
Prior service benefit, arising during period	0	(26,605)	0
Prior service benefit	5,927	2,869	2,869
Net gain	39	175	0
Total recognized in other comprehensive income	$ 40,483	$ (28,353)	$ 1,026