Form 10-K

Retirement
Income
Plan

Non-Qualified
Retirement
Income Plans

Prior service cost

10-K 1 d10k.htm FORM 10-K Form 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, 2008

¨	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 0-296

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 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 (as defined in Rule 12b-2 of the Act).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ 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, 2008, the aggregate market value of the voting stock held by non-affiliates of the registrant was $873,565,546 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2009, there were 44,885,410 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 2009 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
2007 New Mexico Stipulation		Stipulation in Case No. 06-00258-UT dated February 6, 2007, between the Company and other parties to the Company’s rate proceeding before the NMPRC
ANPP Participation Agreement		Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS		Arizona Public Service Company
Common Plant or Common Facilities		Facilities at or related to Palo Verde that are common to all three Palo Verde units
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		The United States Army Air Defense Artillery Center & Ft. Bliss next to El Paso, Texas
Four Corners		Four Corners Generating Station
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MW		Megawatt(s)
MWh		Megawatt-hour(s)
NMPRC		New Mexico Public Regulation Commission
Net dependable generating capability		The maximum load net of plant operating requirements which a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
NRC		Nuclear Regulatory Commission
Palo Verde		Palo Verde Nuclear Generating Station
Palo Verde Participants		Those utilities who share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM		Public Service Company of New Mexico
RGEC		Rio Grande Electric Cooperative
SFAS		Statement of Financial Accounting Standards
SPS		Southwestern Public Service Company
TEP		Tucson Electric Power Company
Texas Commission		Public Utility Commission of Texas
Texas Restructuring Law		Texas Public Utility Regulatory Act Chapter 39, Restructuring of the Texas Electric Utility Industry
TNP		Texas-New Mexico Power Company

(i)

TABLE OF CONTENTS


Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	23
1B	Unresolved Staff Comments	26
2	Properties	28
3	Legal Proceedings	28
4	Submission of Matters to a Vote of Security Holders	28

	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities	29
6	Selected Financial Data	32
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
7A	Quantitative and Qualitative Disclosures About Market Risk	53
8	Financial Statements and Supplementary Data	56
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	128
9A	Controls and Procedures	128
9B	Other Information	128

	PART III
10	Directors and Executive Officers of the Registrant	129
11	Executive Compensation	129
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	129
13	Certain Relationships and Related Transactions	130
14	Principal Accounting Fees and Services	130

	PART IV
15	Exhibits and Financial Statement Schedules	130

(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:

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capital expenditures,

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earnings,

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liquidity and capital resources,

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litigation,

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accounting matters,

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possible corporate restructurings, acquisitions and dispositions,

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compliance with debt and other restrictive covenants,

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interest rates and dividends,

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environmental matters,

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nuclear operations, and

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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:

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our rates in Texas following the five-year moratorium on rate increases which ends June 30, 2010,

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our rates in New Mexico, including the impact of the 2007 New Mexico Stipulation which requires a rate case to be filed by May 29, 2009,

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any changes in our New Mexico fuel and purchased power adjustment clause after the 2009 continuation filing,

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loss of margins on off-system sales due to changes in wholesale power prices or availability of competitive generation resources,

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ability of our operating partners to maintain plant operations and manage operation and maintenance costs at Palo Verde and Four Corners plants including additional costs associated with the degraded cornerstone status of Palo Verde,

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reductions in output at generation plants operated by the Company,

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unscheduled outages including outages at Palo Verde,

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

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electric utility deregulation or re-regulation,

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regulated and competitive markets,

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ongoing municipal, state and federal activities,

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economic and capital market conditions,

(iii)

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changes in accounting requirements and other accounting matters,

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changing weather trends,

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

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changes in environmental regulations,

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political, legislative, judicial and regulatory developments,

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the impact of lawsuits filed against us,

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the impact of changes in interest rates,

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

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

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

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homeland security considerations,

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

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other circumstances affecting anticipated operations, sales and costs.

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

(iv)

PART I

Item 1.

Business

General

El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a net dependable generating capability of approximately 1,503 MW. For the year ended December 31, 2008, the Company’s energy sources consisted of approximately 42% nuclear fuel, 24% natural gas, 6% coal, 28% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 363,000 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 48% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2008). 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 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, two large universities, and oil, copper refining and steel production 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, 2009, the Company had approximately 1,000 employees, 42% 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

The Company’s net dependable generating capability of 1,503 MW consists of the following:


Station	Primary Fuel Type	Net Dependable Generating Capability (MW)
Palo Verde Station	Nuclear Fuel	633
Newman Power Station	Natural Gas	474
Rio Grande Power Station	Natural Gas	229
Four Corners Station	Coal	104
Copper Power Station	Natural Gas	62
Hueco Mountain Wind Ranch	Wind	1

Total		1,503

Palo Verde Station

The Company owns a 15.8% interest, or approximately 633 MW, in the three nuclear generating units and Common Facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company (“SCE”), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District (“SRP”) and the Los Angeles Department of Water and Power. 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.

The NRC has granted facility operating licenses and full power operating licenses for Palo Verde Units 1, 2 and 3, which expire in 2025, 2026 and 2027, respectively. In addition, the Company is separately licensed by the NRC to own its proportionate share of Palo Verde. In December 2008, APS, as agent for the Palo Verde Participants, filed an application with the NRC to extend the Palo Verde licenses for 20 years. Approval, if granted, would be expected in 2011.

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.

corrective actions has resulted in increased operating costs at the plant. Palo Verde is working to correct the issues identified by the NRC and to return to Column I, “licensee response” of the NRC’s action matrix. The Company is currently unable to predict the impact that the NRC’s increased oversight may have on Palo Verde’s future operations and the cost of operations.

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 enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded. At December 31, 2008, the Company’s decommissioning trust fund had a balance of $111.3 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 26, 2008, the Palo Verde Participants approved the 2007 Palo Verde decommissioning study (the “2007 Study”). The 2007 Study estimated that the Company must fund approximately $324.4 million (stated in 2007 dollars) to cover its share of decommissioning costs which was a reduction in decommissioning costs from the 2004 Palo Verde decommissioning study (the “2004 Study”) and will result in lower asset retirement obligations and lower expenses in the future. Although the 2007 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 new facilities until accepted by the DOE for permanent disposal. The 2007 Study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2037. 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. Subsequent judicial decisions required the DOE to start accepting spent nuclear fuel by January 31, 1998. The DOE did not meet that deadline, and the Company cannot currently predict when spent fuel shipments to the DOE’s permanent disposal site 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. On February 28, 2007, APS served on the U.S. Department of Justice its “Initial Disclosure of Claimed Damages” of $93.4 million (the Company’s portion being $14.8 million). This amount includes expenses associated with design, construction, loading, and operation of the Palo Verde independent spent fuel storage installation through December 2006. This amount represents costs incurred to ensure sufficient storage capacity for Palo Verde spent fuel that would not have been incurred had the DOE complied with its standard contract obligation to begin accepting spent fuel from the commercial nuclear power industry beginning in 1998. A 2009 trial date has been set for this case. The Company is unable to predict the outcome of this matter at this time.

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 has 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.

Reactor Vessel Heads. In accordance with applicable NRC requirements, APS conducts regular inspections of reactor vessel heads at Palo Verde Units 1, 2 and 3. In an effort to reduce long-term operating costs at the station related to inspection of the reactor heads, related equipment, and possible repair costs, APS plans to replace reactor vessel heads at Palo Verde. Reactor vessel head replacement is scheduled to occur at Units 1, 2 and 3 in 2010, 2009 and 2010, respectively. The Company’s share of the cash requirements for this project is estimated to be $21.1 million of which $8.9 million had been expended at December 31, 2008.

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 currently at $12.52 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance 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 $11.3 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 one combined cycle generating unit with an aggregate net capability of approximately 474 MW. The units operate primarily on natural gas but can also operate on fuel oil.

The Company received Certificates of Convenience and Necessity (“CCN”) in 2008 from the Texas Commission and NMPRC to construct a 288 MW combined cycle generating unit at the Newman Power Station designated as Newman Unit 5. Construction of Newman Unit 5 began in July 2008 and is expected to be completed in two phases. The first phase, consisting of two 70 MW gas turbine generators, is expected to be completed by June 2009. The second phase will add a heat recovery steam generator and steam turbine to the unit with an expected net capability of 148 MW and is currently expected to be completed before the summer of 2011.

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 capability of approximately 229 MW. The units operate primarily on natural gas but can also operate on fuel oil.

Four Corners Station

The Company owns a 7% interest, or approximately 104 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 capability of 739 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.

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 demands. The unit operates primarily on natural gas but can also operate on fuel oil.

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 32%, can be used as net capability for resource planning purposes.

Transmission and Distribution Lines and Agreements

The Company owns or has significant ownership interests in four major 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 (formerly the North American Electric Reliability Council) 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-Luna-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEP’s Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near Deming, New Mexico, and to the Diablo Substation near Sunland Park, 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.

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 Arroyo Substation located near Las Cruces, New Mexico. This is the primary delivery point for the Company’s generation entitlement from Four Corners, which is transmitted 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 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 (formerly TNP’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 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 and 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 also owns 18.7% 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

The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory 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. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to enforcement by regulatory agencies.

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. For example, recent developments suggest a growing likelihood of future regulation relating to climate change and greenhouse gas emissions. At the federal level, Congress continues to hold many hearings relating to climate change issues and many bills have been introduced to impose regulation through regulatory schemes including a “cap and trade” program. The United States Supreme Court has found carbon dioxide, one of the principal greenhouse gases, to be a “pollutant” under the Clean Air Act, increasing the possibility that the U.S. Environmental Protection Agency will begin to regulate these emissions even in the absence of further action by Congress. In addition, the State of New Mexico, where the Company operates one facility and has an interest in another facility, has joined with California and several other states in the Western Regional Climate Action Initiative and is pursuing initiatives to reduce greenhouse gas emissions in the state. The Company is monitoring these developments and how regulation may affect it. If the United States or individual states in which the Company operates were to regulate greenhouse gas emissions, the Company’s fossil fuel generation assets are likely to face additional costs for monitoring, reporting, controlling, or offsetting these emissions.

emissions of nitrogen oxides from its power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. These requirements become more stringent in 2015, and are anticipated to require even further emissions reductions or additional allowance purchases. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR in its entirety. On December 23, 2008 the DC Circuit Panel granted Rehearing and issued its decision; it remanded CAIR without vacating the original statute. The Company will have to comply with CAIR as written until the EPA rewrites the CAIR as required by the court’s earlier opinion.

The Company takes its environmental compliance seriously and is monitoring these issues so that the Company is best able to effectively adapt to any changes. While the Company strives to prepare for and implement actions necessary to comply with changing environmental regulations, 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. The Company believes it is impossible at present to meaningfully quantify the costs of these potential impacts.

The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet such obligations. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $1.5 million as of December 31, 2008, 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.

Along with many other companies, the Company received from the Texas Commission on Environmental Quality (“TCEQ”) a request for information in 2003 in connection with environmental conditions at a facility in San Angelo, Texas that was operated by the San Angelo Electric Service Company (“SESCO”). In November 2005, TCEQ proposed the SESCO site for listing on the registry of Texas state superfund sites and mailed notice to more than five hundred entities, including the Company, indicating that TCEQ considers each of them to be a “potentially responsible party” at the SESCO site. The Company received from the SESCO working group of potentially responsible parties a settlement offer in May 2006 for remediation and other expenses expected to be incurred in connection with the SESCO site. The Company’s position is that any liability it may have related to the SESCO site was discharged in the Company’s bankruptcy. At this time, the Company has not agreed to a settlement or to otherwise participate in the cleanup of the SESCO site and is unable to predict the outcome of this matter. While the Company has no reason at present to believe that it will incur material liabilities in connection with the SESCO site, it has accrued $0.3 million for potential costs related to this matter.

The EPA has investigated control releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community (“GRIC”) 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. Negotiations with the EPA are ongoing and the Company has accrued $0.2 million for potential costs related to this matter.

carbon monoxide in excess of its permitted emission rates, and failed to properly report these allegedly excess emissions. These allegations were previously made by the NMED in a previously disclosed compliance order, which the NMED withdrew on September 30, 2008. On October 27, 2008, the State of New Mexico amended its complaint to allege approximately 300 additional exceedances of permitted nitrogen dioxide and carbon monoxide emission rates and associated reporting failures between October 2005 and July 2007. The amended complaint seeks civil penalties in the amount of $15,000 per day for each alleged violation. The Company’s motion to dismiss was denied, and the Company is preparing a response to the allegations. While the Company cannot predict the outcome of this suit, it believes these emissions did not violate applicable legal standards.

On April 4, 2007, the Company submitted its application for a New Source Review Air Quality Permit/Prevention of Significant Deterioration (“PSD”) permit to the TCEQ for Newman Unit 5. The Company received approval of its PSD application on May 22, 2008. Additional environmental permits other than the PSD are not required to begin construction of Newman Unit 5 because it will be constructed at an existing plant site, and other permits are currently in place which will encompass the operation of Newman Unit 5.

In May 2007, the EPA finalized a new federal implementation plan which addresses emissions at the Four Corners Station in northwestern New Mexico of which the Company owns a 7% interest in Units 4 and 5. APS, the Four Corners operating agent, has filed suit against the EPA relating to this new federal implementation plan in order to resolve issues involving operating flexibility for emission opacity standards. The Company cannot predict the outcome of the suit filed against the EPA or whether compliance with the new requirements could have an adverse effect on its capital and operating costs.

In December 2008, the Company was notified by El Paso that a property purchased from the Company in May 2005, (Santa Fe Facility), has revealed past contamination consistent with the Company’s past practices conducted at this site. Corrective actions are currently in progress to comply with environmental requirements of the TCEQ. The Company is cooperating with El Paso to address and undertake partial disposal of certain subsurface contaminated materials. The Company has a reserve of $0.7 million for potential costs related to this matter.

Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the EPA, the TCEQ or the NMED which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.

Construction Program

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

The Company’s estimated cash construction costs for 2009 through 2012 are approximately $997 million. 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)
2009	$	251	Production (1)(2)	$	600
2010		264	Transmission		93
2011		181	Distribution		237
2012		301	General		67

Total	$	997	Total	$	997

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

(2)	Includes $385 million for new gas-fired generating capacity (including $155 million for Newman Unit 5), and $30 million for other local generation, $17 million for the Four Corners Station and $168 million for the Palo Verde Station.

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.


Power Source	Years Ended December 31,
Power Source	2008		2007		2006
Nuclear fuel	42	%	43	%	42	%
Natural gas	24		28		25
Coal	6		7		9
Purchased power	28		22		24

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 Texas Commission 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. The Palo Verde Participants have contracts in place that will furnish 100% of Palo Verde’s operational requirements for uranium concentrates, and conversion services through 2010. In addition, the Palo Verde Participants have contracted for 100% of enrichment services through 2013 and 100% of fabrication services until at least 2015 for each Palo Verde unit.

Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The nuclear fuel material market has been affected by supply disruptions and significant price increases in the last few years. The Palo Verde Participants have taken steps to mitigate the effects of future supply disruptions and price increases by changing from a procurement strategy under which nuclear fuel arrives at Palo Verde one month prior to being loaded into a reactor to a strategy where (i) nuclear fuel arrives on site up to three months before being loaded and (ii) a strategic inventory of converted nuclear fuel material sufficient to provide feed stock for one full reactor reload is stored for future use. This change in procurement strategy increased our cash funding requirements in 2007 and 2008. The Company has available $200 million under a revolving credit facility which provides for both working capital and up to $120 million for the financing of nuclear fuel. This facility has a five-year term ending April 11, 2011. At December 31, 2008, approximately $93.7 million had been drawn to finance nuclear fuel. This financing is accomplished through a trust that borrows under the credit facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest. In the Company’s financial statements, the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company.

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 2008, 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 2009. 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 Station. 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.

Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that expired in 2007. These stations have been supplied gas pursuant to this contract in 2008 through a monthly letter extension agreement. The Company is currently finalizing a new contract for an additional 9 years.

Coal

APS, as operating agent for Four Corners, purchases Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The Four Corners coal contract expires in 2016 which coincides with the term of the Four Corners Plant lease with the Navajo Nation. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plant’s operational requirements for its useful life.

Purchased Power

To supplement its own generation and operating reserves, the Company engages in firm and non-firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs and the economics of the transactions. The Company entered into a 20-year contract for the purchase of up to 133 MW of capacity and associated energy beginning in 2006 from SPS. This contract includes a demand charge, fuel charge, variable operations and maintenance charge, and a transmission charge. However, SPS has exercised its right to terminate the contract early due to adverse regulatory action by the Texas Commission regarding transactions under the contract. As a result, the contract will terminate on September 30, 2009.

In June 2006, the Company began exchanging up to 100 MW of capacity and associated energy with Phelps Dodge Energy. The contract provides for Phelps Dodge to deliver energy to the Company from its ownership interest in the Luna Energy Facility, an approximate 570 MW 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 100 MW at a specified price at times when energy is not exchanged. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is exchanged. The parties have agreed to increase the amount to 125 MW for a period of 25 months beginning December 1, 2008. The contract was approved by the FERC and continues through December 31, 2021.

Other purchases of shorter duration were made during 2008 to replace the Company’s generation resources during planned and unplanned outages and for economic reasons as well as to supply off-system sales.

Operating Statistics


	Years Ended December 31,
	2008		2007		2006
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	184,800	$	184,562	$	175,641
Commercial and industrial, small		174,593		168,091		161,359
Commercial and industrial, large		36,318		39,092		40,502
Sales to public authorities		74,427		72,763		68,438

Total retail base revenues		470,138		464,508		445,940
Wholesale:
Sales for resale		1,646		1,919		1,794

Total non-fuel base revenues		471,784		466,427		447,734
Fuel revenues:
Recovered from customers during the period		198,292		197,383		225,441
Under (over) collection of fuel		42,752		17,828		(3,655	)
New Mexico fuel in base rates		68,631		51,487		30,033

Total fuel revenues		309,675		266,698		251,819
Off-system sales		232,500		125,974		95,932
Other		24,971		18,328		20,970

Total operating revenues	$	1,038,930	$	877,427	$	816,455

Number of customers (end of year):
Residential		322,618		317,091		311,923
Commercial and industrial, small		35,850		35,147		32,950
Commercial and industrial, large		49		53		58
Other		4,935		4,853		4,800

Total		363,452		357,144		349,731

Average annual kWh use per residential customer		6,955		7,085		6,852

Energy supplied, net, kWh (in thousands):
Generated		8,023,475		7,707,095		6,908,006
Purchased and interchanged		3,152,396		2,188,904		2,208,661

Total		11,175,871		9,895,999		9,116,667

Energy sales, kWh (in thousands):
Retail:
Residential		2,227,838		2,232,668		2,113,733
Commercial and industrial, small		2,255,585		2,216,428		2,159,599
Commercial and industrial, large		1,102,277		1,195,038		1,204,707
Sales to public authorities		1,448,654		1,384,380		1,343,129

Total retail		7,034,354		7,028,514		6,821,168

Wholesale:
Sales for resale		50,148		48,290		45,397
Off-system sales		3,506,770		2,201,294		1,635,407

Total wholesale		3,556,918		2,249,584		1,680,804

Total energy sales		10,591,272		9,278,098		8,501,972
Losses and Company use		584,599		617,901		614,695

Total		11,175,871		9,895,999		9,116,667

Native system:
Peak load, kW		1,524,000		1,508,000		1,428,000
Net dependable generating capability for peak, kW (1)		1,503,000		1,492,000		1,492,000

Total system:
Peak load, kW (2)		1,669,000		1,680,000		1,675,000
Net dependable generating capability for peak, kW (1) (3)		1,503,000		1,492,000		1,492,000

(1)	2008 includes 11,000 kW increase in generating capability at Palo Verde related to the steam generator replacements for Unit 3.

(2)	Includes spot firm sales and net losses of 145,000 kW, 172,000 kW and 247,000 kW for 2008, 2007 and 2006, respectively.

(3)	Excludes 333,000 kW, 233,000 kW and 133,000 kW for 2008, 2007 and 2006 of firm on and off-peak purchases, respectively.

Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the Texas Commission, the NMPRC, and the FERC. The Texas Commission 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. The decisions of the Texas Commission, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

Texas Freeze Period. The Company has entered into agreements (“Texas Rate Agreements”) with El Paso, Texas Commission Staff and other parties in Texas that provide for most retail base rates to remain at their current level through June 30, 2010. During the rate freeze period, if the Company’s return on equity falls below the bottom of a defined range, the Company has the right to initiate a rate case and seek an adjustment to base rates. If the Company’s return on equity exceeds the top of the range, the Company will refund an amount equal to 50% of the Texas jurisdictional pretax return in excess of the ceiling. The range is based upon a risk premium analysis used in rate proceedings to establish a utility’s return on equity and as of December 2008 the range would be approximately 9.2% to 13.2%. The Company’s return on equity fell within this range during 2008. Also pursuant to the Texas Rate Agreements, the Company agreed to share with its Texas Customers 25% of off-system sales margins and wheeling revenues increasing to 90% of off-system sales margins after June 30, 2010 through June 30, 2015.

Fuel and Purchased Power Costs. Although the Company’s base rates are frozen pursuant to the Texas Rate Agreements, the Company’s actual fuel costs including purchased power energy costs are recoverable from its customers. On August 14, 2008, the Texas Commission approved revisions to its rule for recovery of fuel costs (“Texas Fuel Rule”). The revised Texas Fuel Rule provides two alternative methods for establishing the Company’s fixed fuel factor. The first alternative allows the Company to continue to establish its fuel factor based upon projected fuel and purchased power costs and projected kilowatt-hour sales for a twelve-month period. This alternative allows the Company to revise its fuel factor three times per year at specified dates. The other alternative allows the Company to file with the Texas Commission to establish a formula to determine its fixed fuel factor. Once a formula is approved, the Company could 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 revised Texas Fuel Rule also 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 to continue to be materially over-recovered. The revised 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 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 Texas Commission in fuel reconciliation proceedings.

On July 21, 2008, the Texas Commission issued a final order in the Company’s fuel reconciliation proceeding for the period March 1, 2004 through February 28, 2007 (“Reconciliation

Period”) in PUC Docket No. 34695. At issue was the Company’s request to reconcile a total of $548.4 million in eligible fuel, fuel-related and purchased power expenses incurred to generate and purchase electric energy for its Texas retail customers. The final order adopted a unanimous settlement between the Company, El Paso, the Office of Public Utility Counsel and the Texas Commission Staff providing for a $1.0 million disallowance of fuel and fuel-related expenses during the Reconciliation Period and the exclusion of $0.2 million from the Company’s fuel costs for renewable energy credits, which had previously been reserved by the Company. The Texas Commission did allow $0.6 million in Palo Verde rewards and $0.4 million in interest income that were not previously recognized in the Company’s financial statements. The final order had no significant impact on the Company’s current financial statements.

On January 8, 2008, the Company filed a request with the Texas Commission in PUC Docket No. 35204 to surcharge approximately $30.1 million, including interest, of under-recovered fuel and purchased power costs to be collected over a twelve-month period. The fuel under-recoveries were incurred during the period December 2005 through November 2007. On April 11, 2008, pursuant to a stipulation among the parties to the proceeding, the Texas Commission issued a final order approving the fuel surcharge to be collected over a twelve-month period beginning in May 2008.

On July 8, 2008, the Company filed a petition in PUC Docket No. 35856 with the Texas Commission to increase its fixed fuel factors and to surcharge $39.5 million of under-recovered fuel and purchased power costs including interest, beginning in 2008. The surcharge was based upon actual under-recoveries for the period December 2007 through May 2008 and expected under-recoveries for June and July 2008. On September 25, 2008, the Texas Commission issued a final order approving a unanimous stipulation that resolved all of the issues in the filing. The stipulation allows for an increase in the Company’s Texas jurisdictional fixed fuel factors of $38.8 million or 21.5% annually beginning with customer bills rendered in October 2008. In addition, the requested $39.5 million of fuel under-recoveries will be recovered over an 18-month period beginning in October 2008.

Palo Verde Performance Standards. The Texas Commission established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 36-month period, should fall below 35%, the parties to the Texas Rate Agreements can seek to remove Palo Verde from base rates and seek different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. The Company has calculated the performance rewards for the reporting periods ending in 2008, 2007 and 2006 to be approximately $0.1 million, $0.6 million and $0.4 million, respectively. The 2006 reward was included along with energy costs incurred and fuel revenue billed as part of the Texas Commission’s review during the fuel reconciliation proceeding in PUC Docket No. 34695 as discussed above. Performance rewards are not recorded on the Company’s books until the Texas Commission has ordered a final determination in a fuel proceeding or comparable evidence of collectibility is obtained. Performance penalties would be recorded when assessed as probable by the Company.

The Company agreed to contribute Palo Verde rewards approved in its fuel reconciliation proceeding in PUC Docket No. 23530 to assist low-income customers in paying their utility bills. In

compliance with the Texas Commission’s order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to El Paso approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2008, $4.2 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Company’s balance sheet.

Electric Restructuring. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation activities and retail service activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. However, the Texas Commission has delayed retail competition in the Company’s Texas service territory by approving a rule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization (RTO) in the area that includes the Company’s service territory, including the development of retail market protocols to facilitate retail competition (see “FERC Regulatory Matters – RTO” below). The complete transition to retail competition would occur upon the completion of the last milestone, which would be the Texas Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes this rule delays retail competition in El Paso indefinitely. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory, and the Company 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 the future operations, cash flows and financial condition of the Company, if it were to be implemented.

Renewable Energy Requirements. Notwithstanding the Texas Commission’s approval of a rule further delaying competition in the Company’s Texas service territory, the Company became subject to the renewable energy and energy efficiency requirements of the Texas Restructuring Law on January 1, 2006. Under the renewable energy requirements, the Company is required to annually obtain its pro rata share of renewable energy credits as determined by the Electric Reliability Council of Texas (the “Program Administrator”). The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company expects to meet its obligations for renewable energy credits for 2008.

2007 Energy Efficiency Legislation. New energy efficiency legislation was approved in Texas in June 2007. The new legislation establishes new and increased goals for additional cost-effective energy efficiency for residential and commercial customers equivalent to at least (i) 10% of the annual growth in peak demand for residential and commercial customers by December 31, 2007; (ii) 15% of the annual growth in demand by December 31, 2008; and (iii) 20% of the annual growth in demand by December 31, 2009. Among other things, the new legislation requires the Texas Commission to establish an energy efficiency cost recovery factor for ensuring cost recovery for utility expenditures made to satisfy the energy efficiency goal. The legislation provides that utilities that are unable to establish an energy efficiency cost recovery factor in a timely manner due to a rate freeze will be allowed to defer the costs of complying with the energy efficiency goal and recover such deferred costs at the end of the rate freeze period. On September 8, 2008 in PUC Docket No. 35612, the Texas Commission

approved the Company’s request to defer these costs and recover them through a cost recovery factor upon expiration of its rate freeze period.

New Mexico Regulatory Matters

2007 New Mexico Stipulation. In July 2007, the NMPRC issued a final order approving a stipulation (“2007 New Mexico Stipulation”) addressing all issues in the 2006 rate filing in Case No. 06-00258-UT. The 2007 New Mexico Stipulation provided for a $5.8 million non-fuel base rate increase, established the amount of fuel included in base rates at $0.04288 per kWh, and modified the Company’s Fuel and Purchased Power Cost Adjustment Clause (the “FPPCAC”). Any difference between actual fuel and purchased power costs and the amount included in base rates is recovered or refunded through the FPPCAC. Rates will continue in effect until changed by the NMPRC following the Company’s next rate case. The 2007 New Mexico Stipulation requires the Company to file its next general rate case no later than May 29, 2009 using as a base period the twelve months ending December 31, 2008. Under NMPRC statutes, new rates would become effective no later than July 2010 unless otherwise extended.

The 2007 New Mexico Stipulation provides for recovery through the FPPCAC of the cost of capacity and energy provided to New Mexico retail customers from the deregulated Palo Verde Unit 3. The amount to be recovered is based upon the contract cost of capacity and energy for power purchased under the existing SPS purchased power contract. The 2007 New Mexico Stipulation eliminates the fixed fuel and purchased power cost of $0.021 per kWh for 10% of New Mexico kWh sales and requires 25% of jurisdictional off-system sales margins to be credited to customers through the FPPCAC until July 2010 when 90% of jurisdictional off-system sales margins will be credited to customers. Under NMPRC rules, the Company must file to continue its FPPCAC by July 2009, at which time any party may propose to change the price charged to New Mexico customers for the capacity and energy from Palo Verde Unit 3. The NMPRC has opened a separate docket for a general inquiry into the policies and practices for regulation and administration of FPPCACs in NMPRC Case No. 07-00389.

Notice of Investigation of Rates. On August 3, 2007, the Company received a “Notice of Investigation of Rates of El Paso Electric Company” from the NMPRC in Case No. 07-00317-UT. On August 21, 2007, the NMPRC requested the Company to file a response to the issues, including the reasonableness of fuel and purchased power costs. On September 7, 2007, the Company filed its response and requested that the NMPRC suspend its investigation and close the docket. No further action has been taken by the Commission. The Company is unable at this time to predict the ultimate outcome of this docket.

Renewables. The New Mexico Renewable Energy Act of 2004 as amended by the 2007 New Mexico legislature requires that renewable energy comprise no less than 6% of the Company’s total retail sales to New Mexico customers until January 1, 2011, when the renewable portfolio standard increases to 10% of the Company’s total retail sales to New Mexico customers. After 2011, the renewable portfolio standard, as a percentage of total retail sales to New Mexico customers, increases to 15% by 2015 and 20% by 2020. The Company has met all requirements as approved in the NMPRC’s final orders.

The Company filed its 2008 annual procurement plan on July 1, 2008. In this filing, the Company requested approval of its proposed actions and estimated costs for 2009 and 2010 directed toward meeting the Company’s renewable portfolio standard requirements for 2009 and 2010 and diversity targets in 2011. The Company proposed to meet those requirements through renewable energy resources acquired pursuant to the procurement actions approved by the Commission in the Company’s previous procurement plans and through two new contracts: (i) 66 MW of a 92 MW long-term purchased power agreement with a third party for energy and associated RECs produced from a proposed new solar power facility; and (ii) a three-year contract to purchase wind RECs from SPS. The Company proposed to implement a small distributed generation program to meet the NMPRC’s requirements for diversity of resource type in 2011. In addition, pursuant to the Recommended Decision and Final Order in the Company’s 2007 annual procurement plan in NMPRC Case No. 07-00360-UT, the Company proposed to meet any deficiencies resulting from the 2007 default of the biomass energy supplier through the purchase of the SPS wind RECs. The NMPRC issued a Final Order on December 23, 2008 which approved the Company’s plan with modifications relative to the small distributed generation program. The NMPRC issued a modified Final Order on February 5, 2009 making requested legal clarifications in its original order.

New Mexico Energy Efficiency Legislation. On February 12, 2008, the New Mexico legislature passed House Bill 305, the Utility Customer Load Management bill. This legislation modified the 2005 Efficient Use of Energy Act and requires that electric utilities provide cost-effective energy efficiency programs that will produce savings of 5% of 2005 total retail kWh sales to New Mexico customers by calendar year 2014 and 10% of 2005 retail kWh sales to New Mexico customers by 2020. This legislation was signed by the governor on February 27, 2008.

New Mexico Energy Efficiency Plan Filing. On November 5, 2007, the Company filed its Application for Approval of Energy Efficiency and Load Management Programs in NMPRC Case No. 07-00411-UT. In this filing, the Company requested approval of a number of energy efficiency programs. The Company also proposed a methodology to address disincentives and barriers to utility-provided energy efficiency and proposed to recover the costs of energy efficiency programs through a cost recovery factor. A final order was issued on May 29, 2008 approving the proposed energy efficiency programs and cost recovery factor, but not the recovery of disincentives. The NMPRC has docketed a separate inquiry in NMPRC Case No. 08-00024-UT to investigate options for providing New Mexico public utilities with disincentive cost recovery and incentives for successful efficiency programs and to amend the NMPRC’s Energy Efficiency Rule to conform with 2008 amendments to the Efficient Use of Energy Act that establish energy savings targets and allow incentives.

2007 Long-Term Incentive Plan. On May 18, 2007, the Company filed for NMPRC approval for issuance of common stock for purposes of incentives and compensation. The Company received an order from the NMPRC on April 10, 2008 approving the Company’s request. The Company is required to report on the actual issuance of stock and exercise of stock options under the LTIP as part of the Company’s annual regulatory reporting requirements.

New Mexico Investigation into Executive Compensation. In December 2007, the NMPRC initiated an investigation into executive compensation of investor-owned gas and electric public utilities. In its order initiating the investigation, the NMPRC required each utility to provide information on compensation of executive officers and directors for the period 1977-2006. The Company has provided the requested information. No further action has been taken by the NMPRC.

Generation CCN Filing. On July 18, 2007, the Company filed its application for issuance of a CCN to construct and operate Newman Unit 5 in NMPRC Case No. 07-00301-UT. A hearing was held on January 24, 2008. A final order approving the CCN was issued on April 1, 2008.

Pollution Control Bond Refunding. On March 20, 2008, the Company filed an application with the NMPRC requesting authority for long-term securities transactions necessary to refund and reissue certain Pollution Control Refunding Revenue Bonds (the “PCBs”). On April 22, 2008, the NMPRC issued a final order granting the Company the authority to enter into the securities transactions necessary to refund and reissue the Company’s Series B and Series C PCBs.

Issuance of New Bonds. On April 15, 2008, the Company filed an application with the NMPRC requesting approval of long-term securities transactions necessary to issue up to $300 million in new bonds for terms varying from no less than 5 years to no more than 30 years. Proceeds from the new bonds would be used for the purpose of funding planned capital expenditures, to ensure adequate liquidity and for general corporate purposes. An order approving the issuance of the bonds was issued May 13, 2008. On June 3, 2008, the Company issued 7.50% Senior Notes due on March 15, 2038 with a principal amount of $150 million.

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 a new generating station (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 the 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 his 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.

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 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. If the order is not reversed, the Company will lose the opportunity to receive compensation from TEP for such transmission service in the future. The Company filed a request for rehearing on December 15, 2008 of the FERC’s decision, 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. The FERC suspended the period for ruling on the motion for rehearing on January 14, 2009. If the FERC denies the Company’s request for rehearing or again finds against the Company on rehearing, the Company will have the right to seek judicial review of the order. The Company cannot predict the outcome of such potential future proceedings.

Pollution Control Bond Refunding. On April 4, 2008, the Company filed an application with the FERC requesting authority for long-term securities transactions necessary to refund and reissue certain PCBs. The FERC issued an order on May 1, 2008 granting authority for the securities transactions.

Issuance of New Bonds. On April 17, 2008, the Company filed an application with the FERC requesting approval of long-term securities transactions necessary to issue up to $300 million in one or more series of new bonds for terms varying from no less than five years to no more than 30 years. Proceeds from the new bonds would be used for the purpose of funding planned capital expenditures, to ensure adequate liquidity and for general corporate purposes. An order from the FERC approving the securities transaction was issued on May 16, 2008 and the 7.5% Senior Notes were issued in June 2008.

RTOs. FERC’s rule on RTOs (“Order 2000”) strongly encourages, but does not require, public utilities to form and join regional transmission organizations (“RTOs”). The Company is an active participant in the development of WestConnect. The Company has entered into a memorandum of understanding (“MOU”) with twelve other transmission owners that obligates the parties to participate in and commit resources to ongoing joint efforts, including involvement with stakeholders, customers, local, state and federal regulatory personnel, and other western grid transmission providers to identify, develop and implement cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the western grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company comprises approximately 7% of WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years, if it is achieved at all.

non-firm, point-to-point transmission service across their collective transmission systems at a single rate. Taking coordinated service under the proposal is an alternative to pancaked point-to-point transmission service offered under each member’s individual Open Access Transmission Tariff. The Company does not expect participation in the Proposal to have a material impact on transmission revenues.

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 has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access.

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. 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 entered into a contract on April 18, 2007, as amended on August 29, 2008, to sell up to 100 MW of firm energy and 50 MW of contingent energy to Imperial Irrigation District (“IID”) beginning May 1, 2007, and continuing through April 30, 2009. The contract also provides for the Company to sell up to 100 MW firm energy and 40 MW of contingent energy beginning May 1, 2009 through April 30, 2010. To ensure that power is available to meet the IID contract demand, the Company entered into a contract effective May 1, 2007, as amended and restated on September 3, 2008, to purchase up to 100 MW of firm energy from Credit Suisse Energy, LLC. This contract provides for up to 100 MW of firm energy to be delivered at Palo Verde through April 30, 2010, and 50 MW of energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.

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”). In 2006, the Company provided RGEC with a notice of termination. On March 28, 2008, the Company filed with FERC a power sales agreement for full requirements wholesale electric service (the “Agreement”) to sell capacity and energy to RGEC at a cost-based formula rate. The Company requested that the Agreement become effective April 1, 2008 to replace the power sales agreement that expired March 31, 2008. The Agreement includes a formula-based rate that will be 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. An order accepting the tariff was issued on May 21, 2008 approving the effective date of April 1, 2008.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts for the first quarter of 2009. The Company has also entered into other longer-term sales for which the supply is fully hedged.

Franchises and Significant Customers

El Paso Franchise

The Company has a franchise agreement with El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a franchise fee of 3.25% of revenues and allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso.

Las Cruces Franchise

In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a franchise fee of 2% of revenues for the provision of electric distribution service. Las Cruces exercised its right to extend the franchise for an additional two-year term ending April 30, 2009 and waived its option to purchase the Company’s distribution system pursuant to the terms of the February 2000 settlement agreement. The Company is currently negotiating with Las Cruces on a new franchise agreement.

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 2% of annual operating revenues. The Company signed a contract with Ft. Bliss in October 2008 under which Ft. Bliss will take retail electric service from the Company. The contract is effective until the later of: (i) August 1, 2010 or (ii) new base rates have been approved for the Company in any Texas rate proceeding. In April 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. When the contract with White Sands expires in 2009, the Company anticipates 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.

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 Texas Commission, the NMPRC and the FERC. The Texas Rate Agreements, which established our current retail base rates in Texas, expire on June 30, 2010. It is anticipated that we will need to file a general base rate case in Texas in late 2009 or early 2010, seeking a rate increase after the expiration of the Texas Rate Agreements. In addition, the 2007 New Mexico Stipulation, which established our current retail base rates in New Mexico, requires us to file a general base case in New Mexico no later than May 29, 2009.

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 an 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. 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 upcoming New Mexico rate case in 2009 or the anticipated Texas rate case in late 2009 or early 2010 will result in base rates that will allow us fully to recover our costs including a reasonable return on invested capital. There can be no assurance that our 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 our 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

We have obtained from the Texas Commission and the NMPRC CCNs to construct a new generating unit (Newman Unit 5) in El Paso to meet our expected customer demand for electricity. We have provided the estimated cost of constructing Newman Unit 5 to the Texas Commission and NMPRC. We have risks associated with completing the construction of Newman Unit 5 on time and within projected costs. We have issued new debt to help fund the construction of Newman Unit 5; however, we have risks associated with obtaining additional financing for Newman Unit 5 at reasonable rates as we expect to issue additional debt to finance the completion of the plant.

The cost of financing and constructing Newman Unit 5 will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the Texas Commission 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 the 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 Texas Commission 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 Newman Unit 5.

Turmoil in the Credit Markets and Economic Downturn

The global credit and equity markets are in a state of turmoil, and the overall economy is in a downward trend. These events could have a number of effects on our operations and our capital programs. For example, the tight credit and capital markets may 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. Uncertainties in the credit markets have resulted, and may continue to result, in higher yields and resulting interest expense for approximately $100.6 million of our PCBs for which interest rates are reset weekly and have prevented us from refinancing these securities to date. As a result it will be more difficult and more expensive to refund and reissue such PCBs at fixed rates. In addition, declines in the stock market have reduced and may further reduce the value of our financial assets and decommissioning trust investments and negatively impact our future earnings and cash flow. Such market declines may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. The turmoil in the credit markets may result in changes in the corporate interest rates which we use as the discount rate to determine our pension and other post-retirement liabilities which, in turn, may have an impact on our funding obligations for such plans and trusts. Further, the downturn in the economy may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. We experienced a significant decline in electric usage by our large industrial customers in the fourth quarter of 2008. We expect this decline in large industrial customer usage to continue and could see similar impacts on usage of other customers resulting in a decrease in earnings in 2009. 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 42% of our available net generating capacity and represented approximately 42% of our available energy for the twelve months ended December 31, 2008. Palo Verde comprises approximately 40% 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 83.1% and 77.6% in the twelve months ended December 31, 2008 and 2007, respectively.

The NRC has placed Palo Verde Unit 3 in the “multiple repetitive degraded cornerstone” column of its action matrix which results in an enhanced NRC inspection regimen. We face the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses, including additional costs relating to the enhanced NRC oversight; (ii) increases in the cost of uranium; (iii) the replacement of reactor vessel heads at the Palo Verde units; (iv) an extended outage of any of the Palo Verde units; (v) increases in estimates of decommissioning costs or decrease in the fair value of decommissioning trust fund investments; (vi) the storage of radioactive waste, including spent nuclear fuel; (vii) prolonged reductions in generating output; (viii) insolvency of other Palo Verde Participants; and (ix) compliance with the various requirements and regulations governing commercial nuclear generating stations.

Our ability to increase retail base rates in Texas is limited through June 2010. We cannot seek approval to increase our base rates in Texas in the event of increases in non-fuel costs or loss of revenue unless our return on equity falls below the bottom of a defined range which currently is approximately 9.2%. Our rates in New Mexico will be fixed until after the conclusion of the May 2009 rate filing. 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 or 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 prudently incurred fuel and purchased power expenses from our customers in Texas and New Mexico. The 2007 New Mexico Stipulation provides for energy from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon the contract cost of capacity and fuel for power purchased under the existing SPS purchased power contract. The 2007 New Mexico Stipulation requires the Company to file its FPPCAC according to NMPRC rules, at which time any party may propose to change the price of capacity and related energy from Palo Verde Unit 3 after the SPS purchased power contract is terminated on September 30, 2009. The fuel expense in New Mexico and Texas is subject to reconciliation by the Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In the event that a disallowance 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 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 that may be adjusted three times per year. 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 such as occurred in the

first eight months of 2008, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. At December 31, 2008 and December 31, 2007, the Company had deferred fuel balances of $46.9 million and $27.7 million, respectively. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are particularly vulnerable to this due to the advanced age of several of our gas-fired generating units in or near El Paso. 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 can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as weather, 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 flows 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 Texas Commission approved a rule delaying retail competition in our Texas service territory. This rule identified 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 an RTO 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 flows and financial condition.

Item 1B.

Unresolved Staff Comments

None.

Executive Officers of the Registrant

The executive officers of the Company as of February 15, 2009, were as follows:


Name	Age	Current Position and Business Experience
David W. Stevens	49	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; President and Chief Operating Officer for Panhandle Energy from July 2003 to April 2005.
J. Frank Bates	58	President and Chief Operating Officer since November 2008; Interim President and Chief Executive Officer from February 2008 to November 2008; Executive Vice President and Chief Operating Officer from May 2005 to February 2008; Executive Vice President and Chief Operations Officer from November 2001 to May 2005.
Scott D. Wilson	55	Executive Vice President, Chief Financial and Administrative Officer since February 2006; Senior Vice President, Chief Financial Officer from May 2005 to February 2006; Vice President – Corporate Planning and Controller from February 2005 to May 2005; Controller from September 2003 to February 2005.
Gary D. Sanders	50	Senior Vice President and General Counsel since July 2008; General Counsel from February 2006 to July 2008; Assistant General Counsel and Assistant Secretary from July 2004 to February 2006; Assistant General Counsel from January 2003 to July 2004.
Steve Buraczyk	41	Vice President – Power Marketing and Fuels since July 2008; Director of Power Marketing and Fuels from August 2006 to August 2008; Manager of Power Marketing from August 2004 to August 2006; Supervisor of Resource Management from February 2002 to August 2004.
Steven P. Busser	40	Vice President – Treasurer and Chief Risk Officer since May 2006; Vice President – Regulatory Affairs and Treasurer from February 2005 to April 2006; Treasurer from February 2003 to February 2005.
David G. Carpenter	53	Vice President – Regulatory Services and Controller since September 2008; Vice President – Corporate Planning and Controller from August 2005 to September 2008; Director – Texas Regulatory Services for American Electric Power Services Corporation from June 2000 to August 2005.
Robert C. Doyle	49	Vice President – New Mexico Affairs since February 2007; Director – New Mexico Affairs from January 2007 to February 2007; Manager – Corporate Projects Office from August 2004 to January 2007; Project Manager – Corporate Transition to Competition from January 2004 to August 2004.
Richard G. Gonzalez	52	Vice President – Human Resources since November 2007; Director of Human Resources for Petro Stopping Centers, L.P., from March 2004 to November 2007; Director of Human Resources for Electrolux from March 1996 to March 2004.
Helen Knopp	66	Vice President – Public Affairs since May 2006; Vice President – Customer and Public Affairs from April 1999 to April 2006.
Kerry B. Lore	49	Vice President – Customer Care since December 2008; Vice President – Administration from May 2003 to December 2008.
Rocky R. Miracle	55	Vice President – Corporate Planning since September 2008; Director of Business Operations Support – Texas Operations for American Electric Power from August 2004 to August 2008; Director of Commercial Operations for American Electric Power from June 2002 to July 2004; Director of Mergers and Acquisitions for American Electric Power from June 2000 to May 2002.
Hector R. Puente	52	Vice President – Transmission and Distribution since May 2006; Vice President – Distribution from February 2006 to April 2006; Vice President – Power Generation from April 2001 to February 2006.
Andres Ramirez	48	Vice President – Power Generation since February 2006; Vice President – Safety, Environmental and Resource Planning from July 2005 to February 2006; Executive Director – Operations for Sempra Energy Texas Service from August 2004 to July 2005; Senior Vice President – Power Production for Austin Energy from 2001 to 2004.
Guillermo Silva, Jr.	55	Corporate Secretary since February 2006; Vice President – Information Services from February 2003 to February 2006.
John A. Whitacre	59	Vice President – System Operations and Planning since May 2006; Vice President – Transmission from February 2006 to April 2006; Vice President – Transmission and Distribution from July 2002 to February 2006.

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.

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.

In July 2007, the Company entered into an agreement to lease executive and administrative offices in El Paso, Texas under a lease which expires in May 2018 with three concurrent renewal options of five years each. On February 8, 2008, the Company exercised its right of first refusal in the lease agreement to purchase this office building. All obligations previously incurred relating to this lease were terminated.

In June 2008, the Company entered into an agreement to lease land in El Paso, Texas 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, Texas under a lease which expires in December 2009 with three concurrent renewal options of one year each. The Company also has several other leases for office and parking facilities which expire within the next six 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.

On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The Court granted the Company’s motion to dismiss the case. Wah Chang filed notice of appeal with the U.S. Court of Appeals for the Ninth Circuit, and in November 2007, the Ninth Circuit upheld the dismissal of the suit. Wah Chang filed a motion for rehearing of the appeal, and on January 15, 2008, the Ninth Circuit denied Wah Chang’s motion. No appeal was filed to the U.S. Supreme Court, and the Ninth Circuit decision upholding the dismissal is final.

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

Item 4.

Submission of Matters to a Vote of Security Holders

No matter was submitted to vote of the Company’s security holders through the solicitation of proxies or otherwise during the fourth quarter of 2008.

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities

The Company’s common stock trades on the New York Stock Exchange 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 for the periods indicated below were as follows:


	Sales Price
	High		Low		Close
					(End of period)
2007
First Quarter	$	27.24	$	22.95	$	26.35
Second Quarter		28.19		24.08		24.56
Third Quarter		25.58		20.76		23.13
Fourth Quarter		26.81		22.27		25.57

2008
First Quarter	$	25.54	$	19.04	$	21.37
Second Quarter		23.62		19.66		19.80
Third Quarter		22.01		18.61		21.00
Fourth Quarter		20.90		15.21		18.09

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, 2003 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.

LOGO


	12/31/03	12/31/04	12/31/05	12/31/06	12/31/07	12/31/08
EPE	100	142	158	183	192	136
EEI	100	123	143	172	201	149
NYSE US	100	113	120	142	151	89

As of January 31, 2009, there were 3,694 holders of record of the Company’s common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its stock repurchase programs with the goal of managing its capital structure and enhancing shareholder value.

Since the inception of the stock repurchase programs in 1999, the Company has repurchased a total of approximately 19.8 million shares of its common stock at an aggregate cost of $279.3 million, including commissions. In November 2007, the Board authorized the repurchase of up to 2 million shares of the Company’s outstanding common stock (the “2007 Plan”). No shares remain available under previous plans. During 2008, the Company repurchased 478,634 shares of common stock at an aggregate cost of $9.9 million. As of December 31, 2008, 1,521,366 shares remain authorized to be repurchased under the 2007 Plan. The Company may in the future make purchases of its common stock

pursuant to the 2007 Plan 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.

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

Item 6.

Selected Financial Data

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


	Years Ended December 31,
	2008		2007		2006		2005			2004
Operating revenues	$	1,038,930	$	877,427	$	816,455	$	803,913		$	708,628
Operating income	$	145,736	$	128,321	$	115,562	$	107,883		$	93,071
Income before extraordinary item and cumulative effect of accounting change	$	77,621	$	74,753	$	61,387	$	36,615		$	33,369
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—	$	—	$	6,063	$	—		$	1,802
Cumulative effect of accounting change, net of tax	$	—	$	—	$	—	$	(1,093	)	$	—
Net income	$	77,621	$	74,753	$	67,450	$	35,522		$	35,171
Basic earnings per share:
Income before extraordinary item and cumulative effect of accounting change	$	1.73	$	1.64	$	1.29	$	0.77		$	0.70
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—	$	—	$	0.13	$	—		$	0.04
Cumulative effect of accounting change, net of tax	$	—	$	—	$	—	$	(0.02	)	$	—
Net income	$	1.73	$	1.64	$	1.42	$	0.75		$	0.74
Weighted average number of shares outstanding		44,777,765		45,563,858		47,663,890		47,711,894			47,426,813
Diluted earnings per share:
Income before extraordinary item and cumulative effect of accounting change	$	1.73	$	1.63	$	1.27	$	0.76		$	0.69
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—	$	—	$	0.13	$	—		$	0.04
Cumulative effect of accounting change, net of tax	$	—	$	—	$	—	$	(0.02	)	$	—
Net income	$	1.73	$	1.63	$	1.40	$	0.74		$	0.73
Weighted average number of shares and dilutive potential shares outstanding		44,980,857		45,928,478		48,164,067		48,307,910			48,019,721
Cash additions to utility property, plant and equipment	$	198,711	$	144,588	$	103,182	$	88,263		$	72,092
Total assets	$	2,069,083	$	1,853,888	$	1,714,654	$	1,665,449		$	1,580,835
Long-term debt and financing and capital lease obligations, net of current portion	$	809,718	$	655,111	$	616,130	$	611,018		$	379,636
Common stock equity	$	694,229	$	666,459	$	579,675	$	556,439		$	532,147

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

Note A to the Consolidated Financial Statements contains a summary of significant accounting policies. The preparation of our financial statements requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and related notes for the periods presented and actual results could differ in future periods from those estimates. Critical accounting policies and estimates are both important to the portrayal of our financial condition and results of operations and require complex, subjective judgments and include the following:

•

Application of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”

•

Collection of fuel expense

•

Decommissioning costs and estimated asset retirement obligations

•

Future pension and other postretirement benefit obligations

•

Tax accruals

Application of SFAS No. 71

We apply the provisions of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation,” (“SFAS No. 71”) to our regulated operations in our Texas, New Mexico and FERC jurisdictions. SFAS No. 71 requires a rate regulated enterprise to reflect the economic impact of regulatory decisions in its financial statements. 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. The application of SFAS No. 71 requires our management to make assumptions and estimates as to the amount of costs that regulatory authorities will ultimately permit us to recover. In the event we determine that we can no longer apply SFAS No. 71 to all or a portion of our operations, either as (i) a result of the establishment of retail competition in our service territory; (ii) a change in the regulatory approach for setting rates from cost-based ratemaking to another form of ratemaking; or (iii) other regulatory actions that restrict cost recovery to a level insufficient to recover costs, 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 Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel transactions such that fuel revenues including fuel costs recovered through base rates in New Mexico equal fuel expense except for the fixed portion in New Mexico prior to July 2007. 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. We recorded a liability and a corresponding asset for the fair value of our decommissioning obligation upon implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adjust the liability to its present value periodically over time, and the corresponding asset is depreciated over its useful life. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates.

We and other Palo Verde Participants rely upon decommissioning cost studies and make discount rate, rate of return and inflation projections to determine funding requirements and estimate liabilities related to decommissioning. Every third year outside engineers perform a study to estimate decommissioning costs associated with Palo Verde Units 1, 2 and 3 and associated common areas. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. The funds are invested in professionally managed investment trust accounts. We are required to establish a minimum accumulation and a minimum funding level in our decommissioning trust accounts at the end of each annual reporting period in accordance with the ANPP Participation Agreement. If actual decommissioning costs exceed our estimates, we would incur additional costs related to decommissioning. Further, if the rates of return earned by the trusts fail to meet expectations, we will be required to increase our funding to the decommissioning trust accounts. Although we cannot predict the results of future studies, we believe that the liability we have recorded for our decommissioning costs will be adequate to fund our share of the costs, assuming that Palo Verde Units 1, 2 and 3 operate over their remaining lives (which includes an assessment of the probability of a license extension) and that the DOE assumes responsibility for permanent disposal of spent fuel at plant shut down. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning. Should we become subject to the Texas Restructuring Law, we will be able to collect from regulated transmission and distribution customers the costs of decommissioning. Reference is made to Note E, “Accounting for Asset Retirement Obligations” to the Notes to Consolidated Financial Statements.

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 rate, expected return on plan assets, rate of compensation increase and health care cost inflation. Our assumptions as well as a sensitivity analysis of the effect of hypothetical changes in certain assumptions are set forth in detail in Note L, “Employee Benefits”, to the Notes to Consolidated Financial Statements. 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.

In developing the assumptions, management makes judgments based on the advice of financial and actuarial advisors and our review of third-party and market-based data. These sources include life expectancy tables, surveys of compensation and health care cost trends, and historical and expected return

data on various categories of plan assets. The assumed discount rate applied to future plan obligations is based at December 31 each year on prevailing market interest rates from a yield curve for high quality (AA and better) corporate bonds that would provide future cash flow needed to pay the benefits as they become due. We regularly review our assumptions and conduct a reassessment at least once a year. We do not expect that any such change in assumptions will have a material effect on net income for 2009.

Tax Accruals

We file income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. We are no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2005 and in the state jurisdictions for years prior to 1998. Our federal tax returns are currently under audit for 2005 and 2006. On August 14, 2008, we reached a settlement with the IRS for tax years 1999 through 2004. In the settlement of the tax years 1999 through 2004, we agreed with the IRS to (i) the deduction in the year incurred of 40% of payments related to the repair of the Palo Verde Unit 2 steam generator and the capitalization and depreciation of the remaining 60% of those payments (ii) the capitalization and depreciation of payments related to the dry cask storage facilities for spent nuclear fuel and (iii) the exclusion from taxable income of capital costs paid by third parties for construction of a switchyard. The IRS settlement affected the timing of these deductions but not their ultimate deductibility for federal tax purposes. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in Arizona contests a pollution control credit and the payroll apportionment factor. The Company is contesting these adjustments.

We review our accruals for future liabilities under the provisions of the FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (“FIN 48”). FIN 48 provides a recognition threshold and measurement attribute for the financial statement measurement of tax positions. We have evaluated our tax positions under these provisions including the recognition of interest and penalties on tax benefits that have not been recognized. Although the ultimate outcome of the current examination and appeals cannot be predicted with certainty, we believe that, as of December 31, 2008, we have adequately recognized our expected tax liabilities.

Overview

The following is an overview of our results of operations for the years ended December 31, 2008, 2007 and 2006. Income for the years ended December 31, 2008, 2007 and 2006 is shown below:


	Years Ended December 31,
	2008		2007		2006
Net income before extraordinary item (in thousands)	$	77,621	$	74,753	$	61,387
Basic earnings per share before extraordinary item		1.73		1.64		1.29

The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item and cumulative effect of accounting change between the calendar years ended 2008 and 2007, 2007 and 2006, and 2006 and 2005 (in thousands):


	2008			2007			2006
Prior year December 31 net income before extraordinary item and cumulative effect of accounting change	$	74,753		$	61,387		$	36,615
Change in (net of tax):
Increased (decreased) deregulated Palo Verde Unit 3 proxy market pricing		11,938	(a)		1,007			(324	)
Increased (decreased) off-system sales margins retained		4,172			(1,731	)		2,797
Increased retail non-fuel base revenues		3,547	(b)		11,698	(c)		5,874	(c)
Increased (decreased) AFUDC and capitalized interest		3,456	(d)		6,189	(d)		(533	)
Increased (decreased) transmission wheeling revenue		2,643	(e)		(1,512	)		3,665
Decreased (increased) administrative and general expense		2,066	(f)		3,471	(g)		(229	)
Net fuel recoveries		2,160			(834	)		3,555	(h)
Increased Palo Verde operations and maintenance expense		(7,737	)(i)		(7,114	)(j)		(8,050	)(k)
Decreased (increased) interest on long-term debt		(6,779	)(l)		(751	)		3,168
Decreased (increased) depreciation and amortization		(3,890	)		(599	)		8,694	(m)
Increased (decreased) investment and interest income		(3,659	)(n)		1,983			516
Decreased (increased) maintenance at coal and gas-fired generating plants		(3,630	)(o)		3,516			(2,440	)
Decreased loss on extinguishment of debt		—			—			12,128	(p)
Income tax adjustment		—			(6,174	)(q)		6,174	(q)
Decreased (increased) transmission and distribution operations and maintenance expense		(1,030	)		706			(4,230	)(r)
Decreased (increased) taxes other than income taxes		(374	)		846			(3,427	)(s)
Other		(15	)		2,665			(2,566	)

Current year December 31 net income before extraordinary item	$	77,621		$	74,753		$	61,387

(a)	Deregulated Palo Verde Unit 3 proxy market pricing reflects higher proxy market prices and increased sales of the deregulated portion of Palo Verde Unit 3 to retail customers as the unit did not operate in the fourth quarter of 2007 due to its refueling and replacement of steam generators.

(b)	Retail non-fuel base revenues increased in 2008 compared to 2007 largely due to increased kWh sales to small commercial and industrial customers and other public authorities. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates.

(c)	Retail non-fuel base revenues increased in 2007 compared to 2006 and 2006 compared to 2005 primarily due to increased kWh sales reflecting growth in the number of customers served.

(d)

AFUDC (allowance for funds used during construction) increased for 2008 and 2007 due to increased construction work in progress subject to AFUDC. Capitalized interest increased for 2008 and 2007 due to increased nuclear fuel balances subject to capitalized interest. AFUDC also increased for 2007 compared to 2006 due to the re-application of SFAS No. 71 to our Texas jurisdiction beginning December 31, 2006.

(e)	Transmission wheeling for 2008 increased largely due to wheeling power in southern New Mexico and Arizona partially offset by the reversal of $2.5 million of 2006 wheeling revenues from Tucson Electric Power pursuant to an order of the FERC.

(f)	Administrative and general expenses decreased in 2008 compared to 2007 primarily due to lower pension and other post-retirement benefits expenses reflecting an increase in the discount rate for the associated liabilities.

(g)	Administrative and general expenses decreased in 2007 compared to 2006 due to an increase in capitalized employee salaries and benefits, decreased workers compensation insurance expense, and a sales tax refund.

(h)	Net fuel recoveries increased in 2006 compared to 2005 primarily due to the recovery of purchased power capacity payments in New Mexico in 2006 and increased recovery of transmission expenses in Texas.

(i)	Palo Verde non-fuel operations and maintenance expenses increased due to increased operating costs at all three units in 2008 and higher maintenance costs during refueling outages in 2008 than during refueling outages during 2007.

(j)

Palo Verde non-fuel operations and maintenance expenses increased for 2007 compared to 2006 due to higher maintenance costs at Palo Verde Unit 3 associated with the steam generator replacement and refueling in the fourth quarter of 2007, the higher maintenance costs at Unit 1 associated with refueling that unit in 2007 and higher operating costs at all three units.

(k)	Palo Verde non-fuel operations and maintenance expense increased for 2006 compared to 2005 due to the repairs and modifications at Unit 1 and scheduled maintenance and refueling outages at Unit 2 and Unit 3 in 2006 and higher operating costs at all three units.

(l)	Interest expense on long-term debt increased for 2008 compared to 2007 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.

(m)	Depreciation and amortization decreased in 2006 compared to 2005 due to completing the recovery of certain fresh-start accounting related assets over the term of a rate stipulation in Texas Docket No. 12700 which ended in July 2005.

(n)	Lower investment and interest income in 2008 compared to 2007 is primarily due to impairments of equity securities in our Palo Verde decommissioning trust funds and a decrease in the fair value of our investments in auction rate securities.

(o)	Operation and maintenance costs increased at our fossil-fueled generating plants as planned major maintenance was performed at Newman Unit 3 and Four Corners Unit 5 in 2008. In 2007 no major maintenance was performed at our fossil-fueled generating units.

(p)	Loss on extinguishment of debt in 2006 decreased compared to 2005 reflecting the refinancing of all of our first mortgage bonds in May 2005.

(q)	A reduction in income tax expense was recorded in 2006 to recognize the change in tax rates resulting from changes in the Texas franchise (income) tax law in May 2006 with no comparable activity in 2008 or 2007.

(r)	Transmission and distribution operations and maintenance expense increased primarily due to increased distribution expense and increased net wheeling expenses due to the expiration of an exchange contract.

(s)	Taxes other than income taxes increased in 2006 compared to 2005 due to an increase in the El Paso city franchise fee rate which took effect in August 2005.

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. Under the terms of our rate agreements in Texas and New Mexico, we share 25% of our off-system sales margins with customers in Texas and New Mexico (effective July 1, 2005 and July 1, 2007, respectively). We are also sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a new contract which was effective April 1, 2008. In July 2010, off-system sales margins shared with customers increases to 90%.

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,
	2008		2007		2006
Residential	39	%	40	%	39	%
Commercial and industrial, small	37		36		36
Commercial and industrial, large	8		8		9
Sales to public authorities	16		16		16

Total retail non-fuel base revenues	100	%	100	%	100	%

No retail customer accounted for more than 2% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise more than 75% of our revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. 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,
	2008		2007		2006
January 1 to March 31	22	%	22	%	22	%
April 1 to June 30	26		24		26
July 1 to September 30	29		30		29
October 1 to December 31	23		24		23

Total	100	%	100	%	100	%

Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average for 2008, 2007 and 2006.


	2008	2007	2006	10-year Average
Heating degree days	2,167	2,286	2,020	2,293
Cooling degree days	2,253	2,512	2,457	2,501

Customer growth is a primary driver in the growth of retail sales. The average number of retail customers grew 1.9% and 2.4% in 2008 and 2007, respectively. See the tables presented on pages 42 and 43 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. Retail non-fuel base revenues increased by $5.6 million or 1.2% for the twelve months ended December 31, 2008 when compared to the same period in 2007 primarily as a result of a 1.9% increase in the average number of customers served partially offset by declines in weather-related sales and sales to large commercial and industrial customers. During the twelve months ended December 31, 2008, retail kWh sales to residential customers were restrained by cooler than normal summer weather and warmer than normal winter weather. Cooling degree days in the twelve months ended December 31, 2008 were 10% lower and heating degree days were 5% lower than in the twelve months ended December 31, 2007. Non-fuel base revenues for residential customers increased $0.2 million, or 0.1%. Non-fuel base revenues for small commercial and industrial customers increased $6.5 million, or 3.9% while kWh sales grew 1.8% compared to the same period in 2007 reflecting a 4.6% increase in the average number of customers served. Non-fuel base revenues for public authority customers increased $1.7 million, or 2.3% primarily as a result of increased sales to military bases and colleges and universities. Non-fuel base rate revenues to small commercial and industrial customers and other public authority customers also increased due to a full year of the base rate increase in New Mexico which became effective in July 2007. Non-fuel base revenues from large commercial and industrial customers decreased $2.8 million, or 7.1% due to the decrease in kWh sales to several large commercial and industrial customers and the loss of several of these customers reflecting the impact of the economic downturn in our service territory.

Retail non-fuel base revenues increased by $18.6 million or 4.2% for the twelve months ended December 31, 2007 when compared to the same period in 2006 largely due to increased kWh sales associated with a 2.4% increase in the average number of retail customers served and colder winter weather in the first quarter of 2007 compared to the same period in 2006. Non-fuel base revenues to residential customers increased $8.9 million or 5.1% due to increased kWh sales. KWh sales to residential customers increased 5.6% in the twelve-month period compared to the same period in 2006 largely as a result of a 2.1% increase in the average number of residential customers served and the colder winter weather in the first quarter of 2007. Heating degree days increased 13.2% while cooling degree days increased 2.2% for the twelve-month period in 2007 compared to the same period in 2006. Small commercial and industrial non-fuel base revenues increased $6.7 million or 4.2% in the twelve-month period ended December 31, 2007 reflecting an increase in kWh sales of 2.6% and a small increase in non-fuel base rates in New Mexico effective in July 2007. Other public authorities’ non-fuel base revenues increased $4.3 million or 6.3% due to a 3.1% increase in kWh sales and a small increase in non-fuel base rates in New Mexico. Large commercial and industrial non-fuel base revenues decreased $1.4 million or 3.5% primarily due to customers migrating to the small commercial and industrial class.

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 reflect current fuel costs above the amount recovered in base rates and to recover under-recoveries or refund over-recoveries with a two-month lag. Until terminated on July 1, 2007, a fixed amount of fuel costs was reflected in the New Mexico fuel adjustment clause for 10% of kWh sales. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted up to three times per year. 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.

Natural gas prices increased significantly in the first seven months of 2008 before declining beginning in August 2008 resulting in significant increases in fuel costs including purchased power costs and associated fuel under-recoveries. As a result, deferred fuel revenues in Texas increased substantially during the first eight months of 2008, until the increase in fuel costs was reflected in the fixed fuel factor effective in October 2008. We implemented two fuel surcharges to collect deferred fuel under-recoveries in Texas. In May 2008, we implemented a 12-month surcharge of approximately $30.1 million, including interest. In October 2008, we implemented an 18-month surcharge of approximately $39.5 million including interest. Deferred fuel revenues in New Mexico have increased due to the decision to defer recovery of a portion of New Mexico fuel under-collections until October 2008, after the summer cooling season, to reduce the impact on our customers. In September 2007, we completed the recovery of $53.6 million of fuel under-recoveries through a fuel surcharge from our Texas customers which began in October 2005. We completed the recovery in January 2007 of $34 million of fuel under-recoveries, including interest through the surcharge period, through a fuel surcharge which began in February 2006. In 2008, 2007 and 2006, we collected $26.0 million, $22.9 million and $56.9 million of deferred fuel revenues in Texas through surcharges, respectively. We under-collected current fuel costs and deferred for future recovery $42.8 million in 2008 and $17.8 million in 2007. In 2006, we had an over-collection of fuel costs of $3.7 million. At December 31, 2008, we had deferred fuel under-recovery balances of $39.2 million from our Texas customers and $7.7 million from our New Mexico customers. At December 31, 2007, we had a deferred fuel under-recovery balance of $29.2 million from our Texas customers and a deferred fuel over-recovery balance of $1.5 million from our New Mexico customers.

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. 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, 2008, 2007 and 2006 (in thousands except for MWhs).


	Twelve Months Ended December 31,
	2008		2007		2006
MWh sales		3,506,770		2,201,294		1,635,407
Sales revenues	$	232,500	$	125,974	$	95,932
Fuel cost	$	203,021	$	106,393	$	73,332
Total margins	$	29,479	$	19,581	$	22,600
Retained margins	$	22,137	$	15,514	$	18,261

Off-system sales increased $106.5 million or 84.6% for the twelve months ended December 31, 2008 when compared to 2007 primarily due to increased off-system kWh sales of 59.3% and higher average market prices. Customers receive 25% of off-system sales margins pursuant to the applicable rate agreements. Prior to July 1, 2007, we retained 100% of off-system sales margins in New Mexico and prior to April 1, 2008, we retained 100% of off-system sales margins allocated to our sales for resale customer. For the twelve months ended December 31, 2008, retained margins increased $6.6 million when compared to the same period in 2007 primarily due to the off-system sale to the Imperial Irrigation District (“IID”). In May 2007, we began selling 100 MW of firm energy and 50 MW of contingent energy to IID. The firm portion of this sale is made through a 100 MW purchase of firm energy from Credit Suisse Energy, LLC and the contingent portion is generally from our generating plants.

Off-system sales increased $30.0 million or 31.3% for the twelve months ended December 31, 2007 when compared to 2006 primarily due to increased off-system kWh sales of 34.6%. We had increased energy available for sale in the twelve months of 2007 compared to the same period in 2006 primarily due to the increased energy generated at Palo Verde in the first six months of 2007 compared to the same period in 2006. This increase was partially offset by lower average market prices.

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


Years Ended December 31:	2008		2007		Increase (Decrease)
Years Ended December 31:	2008		2007		Amount			Percent
kWh sales:
Retail:
Residential		2,227,838		2,232,668		(4,830	)	(0.2	)%
Commercial and industrial, small		2,255,585		2,216,428		39,157		1.8
Commercial and industrial, large		1,102,277		1,195,038		(92,761	)	(7.8	)
Sales to public authorities		1,448,654		1,384,380		64,274		4.6

Total retail sales		7,034,354		7,028,514		5,840		0.1

Wholesale:
Sales for resale		50,148		48,290		1,858		3.8
Off-system sales		3,506,770		2,201,294		1,305,476		59.3

Total wholesale sales		3,556,918		2,249,584		1,307,334		58.1

Total kWh sales		10,591,272		9,278,098		1,313,174		14.2

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	184,800	$	184,562	$	238		0.1	%
Commercial and industrial, small		174,593		168,091		6,502		3.9
Commercial and industrial, large		36,318		39,092		(2,774	)	(7.1	)
Sales to public authorities		74,427		72,763		1,664		2.3

Total retail non-fuel base revenues		470,138		464,508		5,630		1.2

Wholesale:
Sales for resale		1,646		1,919		(273	)	(14.2	)

Total non-fuel base revenues		471,784		466,427		5,357		1.1

Fuel revenues:
Recovered from customers during the period		198,292		197,383		909		0.5	(1)
Under (over) collection of fuel		42,752		17,828		24,924		—
New Mexico fuel in base rates		68,631		51,487		17,144		33.3

Total fuel revenues		309,675		266,698		42,977		16.1
Off-system sales		232,500		125,974		106,526		84.6
Other		24,971		18,328		6,643		36.2	(2)

Total operating revenues	$	1,038,930	$	877,427	$	161,503		18.4

Average number of retail customers:
Residential		320,323		315,114		5,209		1.7
Commercial and industrial, small		35,767		34,199		1,568		4.6
Commercial and industrial, large		52		56		(4	)	(7.1	)
Sales to public authorities		4,892		4,834		58		1.2

Total		361,034		354,203		6,831		1.9

(1)	Excludes $26.0 million and $22.9 million of deferred fuel revenues recovered through Texas fuel surcharges in 2008 and 2007, respectively.

(2)	Represents revenues with no related kWh sales.


Years Ended December 31:	2007		2006			Increase (Decrease)
Years Ended December 31:	2007		2006			Amount			Percent
kWh sales:
Retail:
Residential		2,232,668		2,113,733			118,935		5.6	%
Commercial and industrial, small		2,216,428		2,159,599			56,829		2.6
Commercial and industrial, large		1,195,038		1,204,707			(9,669	)	(0.8	)
Sales to public authorities		1,384,380		1,343,129			41,251		3.1

Total retail sales		7,028,514		6,821,168			207,346		3.0

Wholesale:
Sales for resale		48,290		45,397			2,893		6.4
Off-system sales		2,201,294		1,635,407			565,887		34.6

Total wholesale sales		2,249,584		1,680,804			568,780		33.8

Total kWh sales		9,278,098		8,501,972			776,126		9.1

Operating revenues:
Non-fuel base revenues:
Retail:
Residential	$	184,562	$	175,641		$	8,921		5.1	%
Commercial and industrial, small		168,091		161,359			6,732		4.2
Commercial and industrial, large		39,092		40,502			(1,410	)	(3.5	)
Sales to public authorities		72,763		68,438			4,325		6.3

Total retail non-fuel base revenues		464,508		445,940			18,568		4.2

Wholesale:
Sales for resale		1,919		1,794			125		7.0

Total non-fuel base revenues		466,427		447,734			18,693		4.2

Fuel revenues:
Recovered from customers during the period		197,383		225,441			(28,058	)	(12.4	)(1)
Under (over) collection of fuel		17,828		(3,655	)		21,483		—
New Mexico fuel in base rates		51,487		30,033			21,454		71.4

Total fuel revenues		266,698		251,819			14,879		5.9
Off-system sales		125,974		95,932			30,042		31.3
Other		18,328		20,970			(2,642	)	(12.6	)(2)

Total operating revenues	$	877,427	$	816,455		$	60,972		7.5

Average number of retail customers:
Residential		315,114		308,483			6,631		2.1
Commercial and industrial, small		34,199		32,591			1,608		4.9
Commercial and industrial, large		56		58			(2	)	(3.4	)
Sales to public authorities		4,834		4,797			37		0.8

Total		354,203		345,929			8,274		2.4

(1)	Excludes $22.9 million and $56.9 million of deferred fuel revenues recovered through Texas fuel surcharges in 2007 and 2006, respectively.

(2)	Represents revenues with no related kWh sales.

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 42% of our available net generating capacity and approximately 58% of our Company generated energy for the twelve months ended December 31, 2008. Total energy requirements increased 1.3 million MWh in 2008 compared to 2007 almost entirely as a result of increased off-system sales. A significant portion of the increase in off-system sales was related to transactions in which we purchased power to make the sale as reflected in the increase in MWh purchased in the table below.

Our energy expenses increased $122.7 million or 33% for the twelve months ended December 31, 2008 when compared to 2007 primarily due to (i) increased costs of purchased power of $83.7 million due to a 44% increase in MWhs purchased and a 15% increase in the market prices for power, and (ii) increased natural gas costs of $32.2 million due to an 18% increase in the average price of natural gas partially offset by a 3% decrease in MWhs generated with natural gas.

Energy expenses increased $47.3 million for the twelve months ended December 31, 2007 when compared to 2006 primarily due to (i) increased natural gas costs of $37.7 million due to increased natural gas-fired generation, (ii) increased costs of purchased power of $9.8 million due to higher market prices for power, and (iii) increased nuclear fuel costs of $2.8 million due to increased generation. These increases were partially offset in 2007 by a $2.7 million refund related to a gas pipeline reservation fee and a $0.4 million decrease to our coal expense due to a decrease in the amount of coal burned.

The table below details the sources and costs of energy for 2008, 2007 and 2006.


Fuel Type	2008					2007
Fuel Type	Cost		MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)					(in thousands)
Natural Gas	$	250,367	2,679,684	$	93.43	$	218,165	(a)	2,763,016	$	78.96
Coal		13,520	720,951		18.75		11,343		714,164		15.88
Nuclear		25,929	4,622,840		5.61		23,993		4,229,915		5.67

Total		289,816	8,023,475		36.12		253,501		7,707,095		32.89
Purchased power		210,483	3,152,396		66.77		126,833		2,188,904		57.94

Total energy	$	500,299	11,175,871		44.77	$	380,334		9,895,999		38.43


Fuel Type	2006
Fuel Type	Cost		MWh	Cost per MWh
	(in thousands)
Natural Gas	$	180,485	2,287,097	$	78.91
Coal		11,698	827,181		14.14
Nuclear		21,173	3,793,728		5.58

Total		213,356	6,908,006		30.89
Purchased power		116,989	2,208,661		52.97

Total energy	$	330,345	9,116,667		36.24

(a)	Excludes a reservation charge refund of $2.7 million recorded in 2007.

Other operations expense

Other operations expense increased $4.5 million, or 2.3% in 2008 compared to 2007 primarily due to (i) increased Palo Verde operations expense of $7.6 million and (ii) increased distribution expense of $2.1 million. These increases were partially offset by decreased administrative and general expenses of $4.7 million primarily due to a decrease in pension and other post-retirement benefit expenses reflecting an increase in the discount rate for the associated liabilities.

Other operations expense increased $4.4 million, or 2.3% in 2007 compared to 2006 primarily due to increased Palo Verde operations expense of $9.0 million. This increase was partially offset by decreased administrative and general expenses of $5.6 million related to a decrease in workers compensation insurance costs, an increase in capitalized employee salaries and benefits, and a decrease in legal expenses related to regulatory matters.

Maintenance expense

Maintenance expense increased $10.1 million, or 17.8% in 2008 compared to 2007 primarily due to (i) increased maintenance expense at our fossil-fueled generating plants of $4.9 million due to major planned maintenance at Newman Unit 3 and Four Corners Unit 5 in 2008 with no comparable activity in 2007 and (ii) increased Palo Verde maintenance expense of $4.6 million due to increased maintenance during refueling outages in 2008 than during refueling outages in 2007.

Maintenance expense decreased $3.1 million, or 5.1% in 2007 compared to 2006 due to decreased maintenance expense at our gas-fired generating plants of $5.6 million as a result of the timing of planned maintenance, partially offset by increased maintenance expense at Palo Verde of $2.3 million.

Depreciation and amortization expense

Depreciation and amortization expense increased $6.2 million, or 8.9% in 2008 compared to 2007 due to increased depreciable plant balances including the replacement of Palo Verde Unit 3 steam generators in January 2008. Depreciation and amortization expense increased $1.0 million in 2007 compared to 2006 primarily due to increased depreciable plant balances.

Taxes other than income taxes

Taxes other than income taxes increased $0.6 million in 2008 compared to 2007 primarily due to increased property taxes in Texas and New Mexico and payroll taxes at Palo Verde. Taxes other than income taxes decreased $1.3 million in 2007 compared to 2006 primarily due to a decrease in property taxes and the change in the Texas franchise (income) tax law in 2006 which took effect in 2007 offset by an increase in Palo Verde payroll taxes.

Other income (deductions)

Other income (deductions) decreased $1.4 million for the twelve months ended December 31, 2008 compared to the same period last year primarily due to (i) a $4.3 million decrease in income from our decommissioning trust funds including $7.4 million of impairments and realized losses in equity investments when compared to the same period last year and (ii) a decrease in the fair value of our

investments in auction rate securities of $1.7 million in 2008 with no comparable activity in 2007. These decreases were partially offset by (i) increased allowance for equity funds used during construction (“AEFUDC”) of $2.6 million due to higher balances of construction work in progress in 2008 and (ii) an increase in miscellaneous non-operating income of $1.0 million primarily related to an increase in the cash surrender value of key-man life insurance policies from a 10-year interest rate adjustment and the settlement of a death benefit.

Other income (deductions) increased $7.7 million for the twelve months ended December 31, 2007 compared to 2006 primarily due to (i) increased AEFUDC due to the re-application of SFAS No. 71 to our Texas jurisdiction beginning December 31, 2006 and increased construction work in progress subject to AEFUDC in 2007 and (ii) increased investment and interest income due to increased interest income on larger cash and decommissioning trust fund balances.

Interest charges (credits)

Interest charges (credits) increased $9.8 million for the twelve months ended December 31, 2008 compared to the same period last year primarily due to (i) a $6.5 million increase in interest related to the issuance of $150 million of 7.50% Senior Notes in June 2008, and (ii) a $4.5 million increase in interest related to our auction rate pollution control bonds. The interest rates bid in the weekly auctions of our pollution control bonds have increased substantially in 2008. These increases were partially offset by a $1.4 million increase in AFUDC and capitalized interest as a result of increased construction work in progress subject to AFUDC and capitalized interest.

Interest charges (credits) decreased $1.3 million for the twelve months ended December 31, 2007 compared to 2006 primarily due to an increase in allowance for borrowed funds used during construction as a result of the re-application of SFAS No. 71 to our Texas jurisdiction beginning December 31, 2006 and increased construction work in progress and nuclear fuel subject to AFUDC and capitalized interest. This decrease was partially offset by a $1.2 million increase in interest related to our nuclear fuel trust and our pollution control bonds.

Income tax expense

Income tax expense, before extraordinary item, increased $3.4 million for the twelve months ended December 31, 2008 compared to the same period in 2007 due to an increase in pretax income and a reduction in permanent tax differences associated with other post-retirement benefits. Income tax expense for the twelve months ended December 31, 2007 compared to the same period in 2006, increased $8.4 million reflecting higher pre-tax income and a $6.2 million one-time reduction in 2006 deferred income tax expense resulting from a change in the Texas franchise (income) tax rate offset by an increase in a permanent tax benefit associated with the accrual of other post-retirement benefits.

Extraordinary gain

The extraordinary gain on re-application of SFAS No. 71 for 2006 relates to our determination that we met the criteria necessary to re-apply SFAS No. 71 to our Texas jurisdiction at December 31, 2006. The re-application of SFAS No. 71 to our Texas jurisdiction resulted in a $6.1 million

extraordinary gain, net of tax, at December 31, 2006. See Note A of Notes to Consolidated Financial Statements.

New accounting standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” The statement defines fair value, outlines a framework for measuring fair value, and details the required disclosures about fair value measurements. The statement was effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 157 for our financial assets and liabilities in the first quarter of 2008. See Note N of Notes to Consolidated Financial Statements. In February 2007, the FASB issued FASB Staff Position 157-1 (“FSP 157-1”) and FASB Staff Position 157-2 (“FSP 157-2”). FSP 157-1 amends the scope of SFAS No. 157 to exclude FASB Statement No. 13, “Accounting for Leases” and other accounting standards that address fair value measurements of leases from the provisions of SFAS No. 157. FSP 157-2 delays the effective date of SFAS No. 157 for most nonfinancial assets and liabilities to fiscal years beginning after November 15, 2008 except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, FASB issued FASB Staff Position 157-3 (“FSP 157-3”). FSP 157-3 clarifies the application of SFAS No. 157 in a market that is not active and key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP 157-1, FSP 157-2, and FSP 157-3 are not expected to have a significant impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early adoption encouraged. SFAS No. 161 is not expected to have a significant impact on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles. This statement was effective November 15, 2008. SFAS No. 162 did not have a significant impact on our consolidated financial statements.

In December 2008, the FASB issued FASB Staff Position 132(R)-1 (“FSP 132(R)-1”), which amends FASB No. 132(R), “Employers’ Disclosures about Pension and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. FSP 132(R)-1 requires additional disclosure on investment policies and strategies, categories and fair value measurements of plan assets, and significant concentrations of risk. FSP 132(R)-1 is effective for fiscal years ending after December 15, 2009. FSP 132(R)-1 will not have a significant impact on amounts recognized in our consolidated financial statements.

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 capital structure in order to provide us with an opportunity to access the capital markets at a reasonable cost. At December 31, 2008, our capital structure, including common stock, long-term debt, the current portion of long-term debt and financing obligations, consisted of 45.4% common stock equity and 54.6% debt. In June 2008, we issued $150 million of 7.5% Senior Notes to meet current and future cash requirements. The net proceeds from the 7.5% Senior Notes were used to pay down working capital borrowings under our credit facility and the remaining proceeds are expected to fund our construction program through most of 2009. We believe that we will have adequate liquidity through our current cash balances, cash from operations, our credit facility and capital markets, if necessary, to meet all of our anticipated cash requirements for the next 12 months. At December 31, 2008, we had a balance of $91.6 million in cash and cash equivalents. Substantially all of our cash and cash equivalents are currently held in federally insured accounts.

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, non-fuel operation and maintenance costs and taxes. In addition, we may repurchase common stock in the future.

Capital Requirements. During the twelve months ended December 31, 2008, our cash requirements increased due to increased capital expenditures and to fund fuel expenses until they could be collected from customers as discussed below. Projected utility construction expenditures will consist primarily of expanding and updating our transmission and distribution systems, adding new generation, and making capital improvements and replacements at Palo Verde and other generating facilities. We have received regulatory approval in Texas and New Mexico to construct Newman Unit 5, a 288 MW gas-fired combined cycle combustion turbine generating unit, which is scheduled to be completed in two phases at an estimated cost of approximately $245 million. The first phase of Newman Unit 5 is expected to be completed by June 2009 and the second phase is currently expected to be completed before the summer of 2011. See Part I, Item 1, “Business – Construction Program”. In March 2008, we purchased the office building in El Paso, Texas in which we have our general administrative offices. Capital expenditures were $198.7 million in the twelve months ended December 31, 2008 compared to $144.6 million in the twelve months ended December 31, 2007.

Capital requirements have also been impacted by the requirement to fund fuel costs prior to their recovery through fuel recovery mechanisms in Texas, 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 which may be adjusted three times a year. At December 31, 2008, we had a fuel under-recovery balance of $46.9 million including $39.2 million in Texas and $7.7 million in New Mexico. During 2008, fuel under-recoveries increased through August before we could reflect higher fuel costs in fuel rates. Since August 2008, deferred fuel under-recoveries have declined as we have implemented fuel surcharges and increased fuel rates and as natural gas prices have declined.

In October 2008, we implemented an increase in fuel charges in New Mexico to recover fuel under-recoveries accumulated during the summer of 2008 as a result of a voluntary cap on fuel revenues

with the expectation that by the end of the first quarter of 2009, these under-recoveries would be fully recovered. The Texas Commission approved the recovery of fuel under-recoveries in Texas through two fuel surcharges, including a $30.1 million twelve-month surcharge that was placed into effect in May 2008 and a $39.5 million eighteen-month surcharge which was placed into effect in October 2008. The Texas Commission also approved an increase in our fixed fuel factor effective in October 2008. The collection of fuel surcharges will increase our cash flow in 2009.

Our capital requirements for nuclear fuel increased substantially in 2007 as a result of increases in prices for uranium concentrates and an increase in our inventory of nuclear fuel feedstock. This higher balance of nuclear fuel inventory was maintained in 2008. We finance our nuclear fuel inventory through a trust that borrows under our $200 million credit facility to acquire and process the nuclear fuel. Borrowings under the credit facility for nuclear fuel were $93.7 million as of December 31, 2008 and $83.0 million as of December 31, 2007. Up to $120 million of the credit facility may be used to finance nuclear fuel. Amounts not drawn for nuclear fuel are available for general corporate purposes.

The Company does not pay dividends on common stock. Since 1999, we have repurchased approximately 19.8 million shares of common stock at an aggregate cost of $279.3 million, including commissions. During 2008, we repurchased 478,634 shares of common stock at an aggregate cost of $9.9 million. As of December 31, 2008, approximately 1,521,366 shares remain available for repurchase under the currently authorized program. We may make purchases of our stock in the future pursuant to our stock repurchase plan at open market 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.

Our cash requirements for federal and state income taxes decreased $22.0 million in 2008 partially due to refunds of $8.0 million received in 2008 from the settlement of federal tax audits. In addition, accelerated tax depreciation and Texas fuel under-recoveries which are not taxable until recovered from customers decreased current federal income tax payments in 2008 as compared to 2007 by $14.0 million. All other things equal, cash requirements for income taxes will increase as fuel under-recoveries are collected from customers.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $10.7 million and $13.6 million to our retirement plans during the twelve months ended December 31, 2008 and 2007, respectively. We also contributed $3.4 million to our other postretirement benefit plan for both 2008 and 2007 and $7.2 million and $7.0 million to our decommissioning trust funds during the twelve months ended December 31, 2008 and 2007, 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 funds for these plans in order to meet our future obligations.

Capital Resources. Cash flow from operations funded over 70% of our capital requirements in 2008. Cash generated from operations decreased $12.6 million in the twelve months ended December 31, 2008 compared to the same period in 2007 as cash was used to finance deferred fuel under-recoveries. In addition, during 2008, we liquidated $16 million of our investment in debt securities to fund capital requirements. We expect that a significant portion of our construction expenditures will continue to be financed with internal sources of funds, including the collection of deferred fuel revenues.

We also issued $150 million of 7.5% Senior Notes in June 2008 to meet our current and future cash requirements. The net proceeds of $148.7 million from the 7.50% Senior Notes were used to repay $44.0 million of working capital borrowings under our credit facility. The remaining proceeds are expected to help fund our construction program through most of 2009. We believe we will have adequate liquidity through our current cash balances, cash from operations, our credit facility and capital markets, if necessary, to meet all of our anticipated cash requirements for the next 12 months. Our Senior Notes are rated “Baa2” by Moody’s and “BBB” by Standard & Poors. We continue to maintain a $200 million credit facility to provide funds for the purchase of nuclear fuel and to provide liquidity to meet our capital requirements before they can be financed with long-term capital sources. At December 31, 2008, we had an outstanding balance of $93.7 million on our credit facility, all of which pertained to our purchases of nuclear fuel.

Pollution Control Bonds Interest Rates. We currently have approximately $100.6 million of PCBs for which the interest rate is reset weekly. The PCBs are insured by Financial Guaranty Insurance Company (“FGIC”). We have experienced increased yields and resulting interest expense for these auction rate PCBs in 2008. Although there has not yet been a failed auction of these auction rate PCBs, if one were to occur we would be required to pay a default interest rate of 15%. We have obtained approval from the FERC and NMPRC to enter into securities transactions to refund and reissue the Series B $63.5 million and Series C $37.1 million PCBs. We anticipate refunding and reissuing these PCBs as soon as market conditions allow.

Contractual Obligations. Our contractual obligations as of December 31, 2008 are as follows (in thousands):


	Payments due by period
	Total		2009		2010 and 2011		2012 and 2013		2014 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,512,594	$	35,250	$	70,500	$	70,500	$	1,336,344
Pollution control bonds (2)		750,627		18,900		37,800		69,213		624,714
Financing Obligations (including interest):
Nuclear fuel (3)		94,562		23,816		70,746		—		—
Purchase Obligations:
Capacity contract with SPS (4)		8,897		8,897		—		—		—
Other power contracts		20,259		16,559		3,700		—		—
Fuel contracts:
Coal (5)		142,258		18,937		37,873		37,873		47,575
Gas (5)		285,021		70,374		31,945		32,359		150,343
Nuclear fuel (6)		52,133		25,047		19,502		7,584		—
Retirement Plans and Other Postretirement benefits (7)		5,000		5,000		—		—		—
Decommissioning trust funds (8)		245,181		7,893		16,737		19,212		201,339
Operating leases (9)		12,765		2,004		988		848		8,925

Total	$	3,129,297	$	232,677	$	289,791	$	237,589	$	2,369,240

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

(2)	Two series of pollution control bonds are remarketed and the interest rates are set weekly. The remaining two series of pollution control bonds are scheduled for remarketing and/or mandatory tender in 2012 and 2040. Includes interest payments based on the actual interest rate at the end of 2008.

(3)	This reflects current obligations outstanding under the $200 million credit facility used to finance nuclear fuel including interest based on actual interest rates at the end of 2008.

(4)	This represents our contractual obligation to SPS under a contract which terminates on September 30, 2009.

(5)	Amount is based on the minimum volumes per the contract and market price at the end of 2008. 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 an index. The index used is the index at the end of 2008.

(7)

These obligations include our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2009. We have no minimum contractual funding requirement related to our retirement income plan for 2009. However, we may decide to fund at higher levels and expect to contribute $6.3 million and $3.4 million to our retirement plans and postretirement benefit plan in 2009, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note L, Employee Benefits. Minimum contractual funding requirements for 2010 and beyond are not included due to the uncertainty of interest rates and the related return on assets.

(8)	These obligations represent funding requirements under the ANPP Participation Agreement based on the current rate of return on investments.

(9)

In June 2008, we entered into an agreement to lease land in El Paso, Texas 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, Texas under a lease which expires in December 2009 with three concurrent renewal options of one year each. We also have several other leases for office and parking facilities which expire within the next six years.

Off-Balance Sheet Arrangements

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

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 with varying maturities, except for two series of our PCBs which are repriced weekly and our revolving credit facility which is based on floating rates.

We have issued two series of PCBs in the amounts of $63.5 million and $37.1 million with a variable rate that is repriced weekly until they mature in 2040. These PCBs are carried on the balance sheet at their face value. At December 31, 2008, the variable interest rates for the last interest rate reset were 14.60% and 14.70% for the $63.5 million and the $37.1 million PCB series, respectively. Although a failed auction has not yet been experienced, the default interest rate on the weekly auction rate PCBs is 15%. A hypothetical increase to the 15% default interest rate, annualized from the December 31, 2008 rate, would cause an approximate $0.4 million increase in annualized interest expense based upon the last weekly interest rate reset. The weekly auction rate market is experiencing higher interest rates and higher rates of failure particularly in issuances such as ours which are backed by monoline insurance carriers. We have obtained approval from the FERC and NMPRC to enter into securities transactions to refund and reissue these two series of PCBs. We anticipate refunding and reissuing these PCBs as soon as market conditions allow.

To the extent the revolving credit facility is solely utilized for nuclear fuel purchases, interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the Texas Commission and NMPRC rules which establish energy cost recovery clauses (“fuel clauses”). Under these rules and fuel clauses, 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 $57.2 million and $54.1 million as of December 31, 2008 and 2007, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.6 million and $0.7 million based on their fair values at December 31, 2008 and 2007, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $54.1 million and $76.6 million at December 31, 2008 and 2007, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $10.8 million and $15.3 million based on their fair values at December 31, 2008 and 2007, respectively. Further declines from year-end market prices would require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements.

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 Texas Commission 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. They also include 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, 2009, 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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group and are not recorded at their fair value in our financial statements. Because of the operation of the Texas Commission and NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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, 2008. 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, 2008, 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 57 of this report.

Item 8.

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS


		Page
Report of Independent Registered Public Accounting Firm		57

Consolidated Balance Sheets at December 31, 2008 and 2007		58

Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006		60

Consolidated Statements of Comprehensive Operations for the years ended December 31, 2008, 2007 and 2006		61

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2008, 2007 and 2006		62

Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		63

Notes to Consolidated Financial Statements		64

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, 2008 and 2007, 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, 2008. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, 2008 and 2007, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008, 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, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note I to the consolidated financial statements, the Company changed its accounting for income tax uncertainties in 2007.

/s/ KPMG LLP

Houston, Texas

February 25, 2009

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS


ASSETS	December 31,
(In thousands)	2008			2007
Utility plant:
Electric plant in service	$	2,223,066		$	2,047,673
Less accumulated depreciation and amortization		(919,053	)		(858,426	)

Net plant in service		1,304,013			1,189,247
Construction work in progress		205,748			185,122
Nuclear fuel; includes fuel in process of $51,352 and $47,256, respectively		115,749			113,330
Less accumulated amortization		(29,904	)		(37,114	)

Net nuclear fuel		85,845			76,216

Net utility plant		1,595,606			1,450,585

Current assets:
Cash and cash equivalents		91,642			4,976
Investments in debt securities		—			20,000
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,123 and $2,873, respectively		96,507			84,578
Accumulated deferred income taxes		—			14,486
Inventories, at cost		40,153			34,234
Undercollection of fuel revenues		41,034			29,156
Prepayments and other		16,292			14,175

Total current assets		285,628			201,605

Deferred charges and other assets:
Decommissioning trust funds		111,306			130,654
Undercollection of fuel revenues, non current		5,823			—
Regulatory assets		48,616			42,667
Investments in debt securities		2,264			—
Other		19,840			28,377

Total deferred charges and other assets		187,849			201,698

Total assets	$	2,069,083		$	1,853,888

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)


CAPITALIZATION AND LIABILITIES	December 31,
(In thousands except for share data)	2008			2007
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 64,604,852 and 64,400,522 shares issued, and 127,800 and 119,403 restricted shares, respectively	$	64,733		$	64,520
Capital in excess of stated value		295,346			292,614
Retained earnings		643,322			565,701
Accumulated other comprehensive income (loss), net of tax		(29,364	)		13,540

		974,037			936,375
Treasury stock, 19,848,900 and 19,370,266 shares, respectively, at cost		(279,808	)		(269,916	)

Common stock equity		694,229			666,459
Long-term debt, net of current portion		739,652			590,894
Financing obligations, net of current portion		70,066			64,217

Total capitalization		1,503,947			1,321,570

Current liabilities:
Current portion of long-term debt and financing obligations		23,587			18,798
Accounts payable, principally trade		61,550			58,013
Accumulated deferred income taxes		4,209			—
Taxes accrued		23,798			20,500
Interest accrued		7,519			4,347
Other		24,146			24,359

Total current liabilities		144,809			126,017

Deferred credits and other liabilities:
Accumulated deferred income taxes		175,816			183,349
Accrued postretirement benefit liability		85,797			67,385
Asset retirement obligation		78,037			79,709
Accrued pension liability		39,101			30,088
Regulatory liabilities		14,469			14,876
Other		27,107			30,894

Total deferred credits and other liabilities		420,327			406,301

Commitments and contingencies
Total capitalization and liabilities	$	2,069,083		$	1,853,888

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except for share data)


	Years Ended December 31,
	2008			2007			2006
Operating revenues	$	1,038,930		$	877,427		$	816,455

Energy expenses:
Fuel		289,816			250,789			213,356
Purchased and interchanged power		210,483			126,833			116,989

		500,299			377,622			330,345

Operating revenues net of energy expenses		538,631			499,805			486,110

Other operating expenses:
Other operations		200,408			195,901			191,504
Maintenance		67,110			56,974			60,044
Depreciation and amortization		75,571			69,397			68,446
Taxes other than income taxes		49,806			49,212			50,554

		392,895			371,484			370,548

Operating income		145,736			128,321			115,562

Other income (deductions):
Allowance for equity funds used during construction		8,279			5,708			882
Investment and interest income, net		3,798			9,605			6,456
Miscellaneous non-operating income		2,477			1,431			861
Miscellaneous non-operating deductions		(3,619	)		(4,386	)		(3,589	)

		10,935			12,358			4,610

Interest charges (credits):
Interest on long-term debt and financing obligations		47,605			36,844			35,652
Other interest		1,208			804			1,092
Capitalized interest		(3,620	)		(3,235	)		(3,580	)
Allowance for borrowed funds used during construction		(3,973	)		(2,954	)		(445	)

		41,220			31,459			32,719

Income before income taxes and extraordinary item		115,451			109,220			87,453
Income tax expense		37,830			34,467			26,066

Income before extraordinary item		77,621			74,753			61,387
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—			6,063

Net income	$	77,621		$	74,753		$	67,450

Basic earnings per share:
Income before extraordinary item	$	1.73		$	1.64		$	1.29
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—			0.13

Net income	$	1.73		$	1.64		$	1.42

Diluted earnings per share:
Income before extraordinary item	$	1.73		$	1.63		$	1.27
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—			0.13

Net income	$	1.73		$	1.63		$	1.40

Weighted average number of shares outstanding		44,777,765			45,563,858			47,663,890

Weighted average number of shares and dilutive potential shares outstanding		44,980,857			45,928,478			48,164,067

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)


	Years Ended December 31,
	2008			2007			2006
Net income	$	77,621		$	74,753		$	67,450
Other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs:
Net gain (loss) arising during period		(30,587	)		40,625			—
Reclassification adjustments included in net income for amortization of:
Prior service cost		(2,754	)		(2,754	)		—
Net (gain) loss		(152	)		3,385			—
Minimum pension liability adjustment		—			—			16,923
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period		(29,779	)		5,835			8,805
Reclassification adjustments for net (gains) losses included in net income		2,876			(1,683	)		661
Net gains (losses) on cash flow hedges:
Reclassification adjustment for interest expense included in net income		297			278			263

Total other comprehensive income (loss) before income taxes		(60,099	)		45,686			26,652

Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and postretirement benefit costs		11,922			(18,037	)		—
Minimum pension liability adjustment		—			—			(6,348	)
Net unrealized gains (losses) on marketable securities		5,381			(830	)		(1,893	)
Losses on cash flow hedges		(108	)		(104	)		(99	)

Total income tax benefit (expense)		17,195			(18,971	)		(8,340	)

Other comprehensive income (loss), net of tax		(42,904	)		26,715			18,312

Comprehensive income	$	34,717		$	101,468		$	85,762

See accompanying notes to consolidated financial statements.

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			Deferred and Unearned Compensation			Retained Earnings		Accumulated Other Comprehensive Income (Loss), Net of Tax			Treasury Stock				Total Common Stock Equity
	Shares		Amount			Capital in Excess of Stated Value			Deferred and Unearned Compensation			Retained Earnings					Shares	Amount			Total Common Stock Equity
Balances at December 31, 2005	63,507,429		$	63,507		$	275,393		$	2,150		$	421,632	$	(30,167	)	15,365,108	$	(176,076	)	$	556,439
Reclassification adjustment upon adoption of SFAS No. 123r							2,150			(2,150	)											—
Restricted common stock grants and deferred compensation	77,054			77			1,317															1,394
Performance share awards	68,425			69			1,371															1,440
Stock awards withheld for taxes	(28,640	)		(29	)		(573	)														(602	)
Deferred taxes on stock incentive plan							955															955
Stock options exercised	396,560			397			2,743															3,140
Net income													67,450									67,450
Other comprehensive income															18,312							18,312
SFAS No. 158 adoption, net of tax of $3,879															(6,461	)						(6,461	)
Treasury stock acquired, at cost																	2,660,820		(62,392	)		(62,392	)

Balances at December 31, 2006	64,020,828			64,021			283,356			—			489,082		(18,316	)	18,025,928		(238,468	)		579,675
Restricted common stock grants and deferred compensation	109,318			109			1,348															1,457
Performance share awards	58,650			59			660															719
Stock awards withheld for taxes	(28,492	)		(28	)		(669	)														(697	)
Forfeitures and lapsed restricted common stock	(24,379	)		(25	)		(4	)														(29	)
Deferred taxes on stock incentive plan							3,992															3,992
Stock options exercised	384,000			384			3,931															4,315
Net income													74,753									74,753
FIN 48 adoption													1,866									1,866
Other comprehensive income															26,715							26,715
Adjustment for tax effect of SFAS No. 158															5,141							5,141
Treasury stock acquired, at cost																	1,344,338		(31,448	)		(31,448	)

Balances at December 31, 2007	64,519,925			64,520			292,614			—			565,701		13,540		19,370,266		(269,916	)		666,459
Restricted common stock grants and deferred compensation	117,550			118			1,328															1,446
Performance share awards	41,958			42			715															757
Stock awards withheld for taxes	(17,931	)		(18	)		(413	)														(431	)
Forfeitures and lapsed restricted common stock	(36,850	)		(37	)																	(37	)
Deferred taxes on stock incentive plan							43															43
Stock options exercised	108,000			108			1,059															1,167
Net income													77,621									77,621
Other comprehensive loss															(42,904	)						(42,904	)
Treasury stock acquired, at cost																	478,634		(9,892	)		(9,892	)

Balances at December 31, 2008	64,732,652		$	64,733		$	295,346		$	—		$	643,322	$	(29,364	)	19,848,900	$	(279,808	)	$	694,229

See accompanying notes to consolidated financial statements.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Years Ended December 31,
	2008			2007			2006
Cash Flows From Operating Activities:
Net income	$	77,621		$	74,753		$	67,450
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		75,571			69,397			68,446
Amortization of nuclear fuel		19,705			18,166			15,387
Extraordinary gain on the re-application of SFAS No. 71, net of tax		—			—			(6,063	)
Deferred income taxes, net		16,646			10,392			19,751
Allowance for equity funds used during construction		(8,279	)		(5,708	)		(882	)
Other amortization and accretion		13,784			12,173			12,945
Gain on sale of assets		(137	)		(195	)		(766	)
Unrealized loss on investments in debt securities		1,736			—			—
Other operating activities		6,973			(561	)		(941	)
Change in:
Accounts receivable		(11,929	)		2,152			(10,724	)
Inventories		(4,717	)		(3,438	)		(2,792	)
Net (undercollection) overcollection of fuel revenues		(19,161	)		4,886			59,749
Prepayments and other		(1,582	)		(1,177	)		(8,676	)
Accounts payable		(4,306	)		12,508			(3,858	)
Taxes accrued		16,875			4,204			3,781
Interest accrued		3,172			(43	)		(94	)
Other current liabilities		1,248			(513	)		720
Deferred charges and credits		(13,487	)		(14,686	)		4,565

Net cash provided by operating activities		169,733			182,310			217,998

Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment		(198,711	)		(144,588	)		(103,182	)
Cash additions to nuclear fuel		(25,767	)		(52,400	)		(17,602	)
Proceeds from sale of assets		563			5,305			992
AFUDC and capitalized interest:
Utility property, plant and equipment		(12,252	)		(8,662	)		(4,238	)
Nuclear fuel		(3,620	)		(3,235	)		(669	)
Allowance for equity funds used during construction		8,279			5,708			882
Decommissioning trust funds:
Purchases, including funding of $7.2 million, $7.0 million and $6.7 million, respectively		(67,169	)		(116,165	)		(106,403	)
Sales and maturities		53,447			105,201			98,085
Purchases of debt securities		—			(20,000	)		—
Proceeds from sale of investments in debt securities		16,000			—			—
Other investing activities		(2,201	)		192			867

Net cash used for investing activities		(231,431	)		(228,644	)		(131,268	)

Cash Flows From Financing Activities:
Proceeds from exercise of stock options		1,167			4,315			3,140
Repurchases of common stock		(9,892	)		(31,448	)		(62,392	)
Proceeds from issuance of long-term senior notes		148,719			—			—
Financing obligations:
Proceeds		73,179			56,083			20,373
Payments		(62,541	)		(19,308	)		(16,040	)
Excess tax benefits from long-term incentive plans		382			2,395			1,417
Other financing activities		(2,650	)		(828	)		(1,083	)

Net cash provided by (used for) financing activities		148,364			11,209			(54,585	)

Net increase (decrease) in cash and cash equivalents		86,666			(35,125	)		32,145
Cash and cash equivalents at beginning of period		4,976			40,101			7,956

Cash and cash equivalents at end of period	$	91,642		$	4,976		$	40,101

See accompanying notes to consolidated financial statements.

INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Note A. Summary of Significant Accounting Policies		65

Note B. Regulation		71

Note C. Regulatory Assets and Liabilities		80

Note D. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant		81

Note E. Accounting for Asset Retirement Obligations		85

Note F. Common Stock		86

Note G. Accumulated Other Comprehensive Income (Loss)		93

Note H. Long-Term Debt and Financing Obligations		94

Note I. Income Taxes		96

Note J. Commitments, Contingencies and Uncertainties		99

Note K. Litigation		106

Note L. Employee Benefits		106

Note M. Franchises and Significant Customers		118

Note N. Financial Instruments and Investments		118

Note O. Supplemental Statements of Cash Flow Disclosures		126

Note P. Selected Quarterly Financial Data (Unaudited)		127

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 services previously provided by the Company’s Energy Services Business Group. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. See Note J. 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 SFAS No. 71. Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Under this accounting standard, the Company includes an allowance for equity and borrowed funds used during construction (“AEFUDC” and “ABFUDC”) as a cost of construction of electric plant in service. The allowance for equity funds used during construction is recognized as income and the allowance for borrowed funds used during construction is shown as capitalized interest charges in the Company’s statement of operations. Also under this accounting standard, certain recoverable costs are shown 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). 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 C.

Prior to April 1, 2008, the Company did not apply SFAS No. 71 to the Company’s FERC jurisdictional operations. The Company’s FERC jurisdictional customer, Rio Grande Electric Cooperative (“RGEC”), had been operating under an agreement which terminated March 31, 2008. The FERC approved a new agreement with RGEC effective April 1, 2008. The rates charged RGEC are based upon

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the Company’s actual cost of service and are updated annually. The Company determined that the new agreement re-established regulated cost-based rates for RGEC and met the criteria for the re-application of SFAS No. 71 as of April 1, 2008. The re-application of SFAS No. 71 to the Company’s FERC jurisdictional customer resulted in a $0.2 million increase in regulatory assets and a $0.2 million pre-tax gain which was recorded as miscellaneous non-operating income in the second quarter of 2008.

The Company applies SFAS No. 71 to its New Mexico and Texas jurisdictions. Prior to December 31, 2006, the Company did not apply SFAS No. 71 to its Texas jurisdictional operations. The Public Utility Commission of Texas (“Texas Commission”) issued an order in December 2006 approving provisions of rate agreements (“Texas Rate Agreements”) with the City of El Paso (“El Paso”), Texas Commission Staff, and other parties in Texas that established a regulatory structure under which the Company’s Texas jurisdictional rates are based upon its regulated cost of service. Based upon the Texas Rate Agreements, the Company determined that it met the criteria for the re-application of SFAS No. 71 to its Texas jurisdiction on December 31, 2006. As a result of the re-application of SFAS No. 71 to the Company’s Texas jurisdiction at December 31, 2006, the Company recorded regulatory assets of $9.6 million, related accumulated deferred income tax liability of $3.5 million, and recognized an extraordinary gain of $6.1 million, net of tax. Regulatory assets recorded as of December 31, 2006 are currently being recovered through the Texas fixed fuel factor. Other regulatory assets and liabilities will be recorded when recognized in Texas rates.

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 SFAS No. 130, “Reporting Comprehensive Income.”

Utility Plant. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from 3 to 34 years). The cost of repairs and minor replacements are charged to the appropriate operating expense accounts and the cost of renewals and betterments are capitalized. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original 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 D.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets, such as property, plant, and equipment and purchased intangibles subject to amortization, 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 nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in SFAS No. 71. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. The AFUDC rates utilized in 2008 and 2007 were 8.57% and 8.43%, respectively. Prior to the re-application of SFAS No. 71, the Company capitalized interest cost to construction work in progress and nuclear fuel in process in accordance with SFAS No. 34, “Capitalization of Interest Cost” for its FERC and Texas jurisdictional operations. See Application of SFAS No. 71 discussed above. The AFUDC rate applied for the New Mexico jurisdiction for 2006 was 8.73%.

Asset Retirement Obligation. The Company complies with SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 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 SFAS No. 143 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. Under the statement, 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). Effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies that the term “conditional” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity even if the timing and/or settlement are conditional on a future event that may or may not be within the control of an entity. See Note E.

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

Investments in Debt Securities. The Company invested excess cash in auction rate securities with contract maturity dates that extended beyond three months. These securities have interest rates that reset frequently, and historically had provided a liquid market to sell the securities to meet cash requirements. These securities were and still are classified as trading securities by the Company. The auction rate securities had successful auctions through January 2008. However, since February 13, 2008, auctions for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$4.0 million of these investments have not been successful, resulting in the inability to liquidate these investments. These investments continue to pay interest. The Company reclassified them to deferred charges and other assets as of March 31, 2008 and has adjusted the carrying amount to fair value. See Note N.

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 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 N.

Derivative Accounting. The Company complies with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group. This standard 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 N.

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 being billed under base rates and a fixed fuel factor approved by the Texas Commission. The Company’s New Mexico retail customers and its sales for resale customer are being 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 in these jurisdictions 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 these customers is reflected as over/undercollection of fuel revenues in the consolidated balance sheets. See Note B.

Revenues. Accounts receivable include accrued unbilled revenues of $18.6 million and $17.9 million at December 31, 2008 and 2007, respectively. The Company presents sales net of sales taxes in its consolidated statements of operations.

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Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2008, 2007 and 2006 are as follows (in thousands):


	2008		2007		2006
Balance at beginning of year	$	2,873	$	2,999	$	2,474
Additions:
Charged to costs and expense		3,328		2,875		3,454
Recovery of previous write-offs		1,184		1,152		1,062
Uncollectible receivables written off		4,262		4,153		3,991

Balance at end of year	$	3,123	$	2,873	$	2,999

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes under the provisions of SFAS No. 109, Accounting for Income Taxes (“SFAS No. 109”). Under this method, 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 Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). A tax liability has been established to recognize interest and penalties on tax benefits that have not been recognized. See Note I.

Earnings per Share. Basic earnings per share is computed by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares and the dilutive impact of the sum of unvested restricted stock, performance shares, and the stock options that were outstanding during the period with the amount of outstanding options calculated using the treasury stock method.

Stock-Based Compensation. The Company has a stock-based long-term incentive plan. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised) “Accounting for Stock-Based Compensation,” which requires a public entity 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 (with some limited exceptions). 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. SFAS No. 123 (revised) applies to all awards granted after January 1, 2006 and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of January 1, 2006 shall be expensed as the requisite service is rendered on or after such date, see Note F.

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

Other New Accounting Standards. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” The statement defines fair value, outlines a framework for measuring fair value, and details the required disclosures about fair value measurements. The statement was effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 157 for the Company’s financial assets and liabilities in the first quarter of 2008. See Note N of Notes to Consolidated Financial Statements. In February 2007, the FASB issued FASB Staff Position 157-1 (“FSP 157-1”) and FASB Staff Position 157-2 (“FSP 157-2”). FSP 157-1 amends the scope of SFAS No. 157 to exclude FASB Statement No. 13, “Accounting for Leases” and other accounting standards that address fair value measurements of leases from the provisions of SFAS No. 157. FSP 157-2 delays the effective date of SFAS No. 157 for most nonfinancial assets and liabilities to fiscal years beginning after November 15, 2008 except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. In October 2008, FASB issued FASB Staff Position 157-3 (“FSP 157-3”). FSP 157-3 clarifies the application of SFAS No. 157 in a market that is not active and key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP 157-1, FSP 157-2, and FSP 157-3 are not expected to have a significant impact on the Company’s consolidated financial statements.

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significant impact on the Company’s amounts recognized in the Company’s consolidated financial statements.

B. Regulation

General

Texas Regulatory Matters

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exceeds a threshold material amount and it expects to continue to be materially over-recovered. The revised 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 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 Texas Commission in fuel reconciliation proceedings.

On July 21, 2008, the Texas Commission issued a final order in the Company’s fuel reconciliation proceeding for the period March 1, 2004 through February 28, 2007 (“Reconciliation Period”) in PUC Docket No. 34695. At issue was the Company’s request to reconcile a total of $548.4 million in eligible fuel, fuel-related and purchased power expenses incurred to generate and purchase electric energy for its Texas retail customers. The final order adopted a unanimous settlement between the Company, El Paso, the Office of Public Utility Counsel and the Texas Commission Staff providing for a $1.0 million disallowance of fuel and fuel-related expenses during the Reconciliation Period and the exclusion of $0.2 million from the Company’s fuel costs for renewable energy credits, which had previously been reserved by the Company. The Texas Commission did allow $0.6 million in Palo Verde rewards and $0.4 million in interest income that were not previously recognized in the Company’s financial statements. The final order had no significant impact on the Company’s current financial statements.

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possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 36-month period, should fall below 35%, the parties to the Texas Rate Agreements can seek to remove Palo Verde from base rates and seek different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. The Company has calculated the performance rewards for the reporting periods ending in 2008, 2007 and 2006 to be approximately $0.1 million, $0.6 million and $0.4 million, respectively. The 2006 reward was included along with energy costs incurred and fuel revenue billed as part of the Texas Commission’s review during the fuel reconciliation proceeding in PUC Docket No. 34695 as discussed above. Performance rewards are not recorded on the Company’s books until the Texas Commission has ordered a final determination in a fuel proceeding or comparable evidence of collectibility is obtained. Performance penalties would be recorded when assessed as probable by the Company.

The Company agreed to contribute Palo Verde rewards approved in its fuel reconciliation proceeding in PUC Docket No. 23530 to assist low-income customers in paying their utility bills. In compliance with the Texas Commission’s order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to El Paso approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2008, $4.2 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Company’s balance sheet.

Renewable Energy Requirements. Notwithstanding the Texas Commission’s approval of a rule further delaying competition in the Company’s Texas service territory, the Company became subject to

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the renewable energy and energy efficiency requirements of the Texas Restructuring Law on January 1, 2006. Under the renewable energy requirements, the Company is required to annually obtain its pro rata share of renewable energy credits as determined by the Electric Reliability Council of Texas (the “Program Administrator”). The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company expects to meet its obligations for renewable energy credits for 2008.

New Mexico Regulatory Matters

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of New Mexico kWh sales and requires 25% of jurisdictional off-system sales margins to be credited to customers through the FPPCAC until July 2010 when 90% of jurisdictional off-system sales margins will be credited to customers. Under NMPRC rules, the Company must file to continue its FPPCAC by July 2009, at which time any party may propose to change the price charged to New Mexico customers for the capacity and energy from Palo Verde Unit 3. The NMPRC has opened a separate docket for a general inquiry into the policies and practices for regulation and administration of FPPCACs in NMPRC Case No. 07-00389.

The Company filed its 2008 annual procurement plan on July 1, 2008. In this filing, the Company requested approval of its proposed actions and estimated costs for 2009 and 2010 directed toward meeting the Company’s renewable portfolio standard requirements for 2009 and 2010 and diversity targets in 2011. The Company proposed to meet those requirements through renewable energy resources acquired pursuant to the procurement actions approved by the Commission in the Company’s previous procurement plans and through two new contracts: (i) 66 MW of a 92 MW long-term purchased power agreement with a third party for energy and associated RECs produced from a proposed new 92 MW solar power facility; and (ii) a three-year contract to purchase wind RECs from SPS. The Company proposed to implement a small distributed generation program to meet the NMPRC’s requirements for diversity of resource type in 2011. In addition, pursuant to the Recommended Decision and Final Order in the Company’s 2007 annual procurement plan in NMPRC Case No. 07-00360-UT, the Company proposed to meet any deficiencies resulting from the 2007 default of the biomass energy supplier through the purchase of the SPS wind RECs. The NMPRC issued a Final Order on December 23, 2008 which approved the Company’s plan with modifications relative to the small distributed generation program. The NMPRC issued a modified Final Order on February 5, 2009 making requested legal clarifications in its original order.

New Mexico Energy Efficiency Legislation. On February 12, 2008, the New Mexico legislature passed House Bill 305, the Utility Customer Load Management bill. This legislation modified the 2005

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Efficient Use of Energy Act and requires that electric utilities provide cost-effective energy efficiency programs that will produce savings of 5% of 2005 total retail kWh sales to New Mexico customers by calendar year 2014 and 10% of 2005 retail kWh sales to New Mexico customers by 2020. This legislation was signed by the governor on February 27, 2008.

2007 Long-Term Incentive Plan (“LTIP”). On May 18, 2007, the Company filed for NMPRC approval for issuance of common stock for purposes of incentives and compensation. The Company received an order from the NMPRC on April 10, 2008 approving the Company’s request. The Company is required to report on the actual issuance of stock and exercise of stock options under the LTIP as part of the Company’s annual regulatory reporting requirements.

Issuance of New Bonds. On April 15, 2008, the Company filed an application with the NMPRC requesting approval of long-term securities transactions necessary to issue up to $300 million in new

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bonds for terms varying from no less than 5 years to no more than 30 years. Proceeds from the new bonds would be used for the purpose of funding planned capital expenditures, to ensure adequate liquidity and for general corporate purposes. An order approving the issuance of the bonds was issued May 13, 2008. On June 3, 2008, the Company issued 7.50% Senior Notes due on March 15, 2038 with a principal amount of $150 million.

Federal Regulatory Matters

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 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. If the order is not reversed, the Company will lose the opportunity to receive compensation from TEP for such transmission service in

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the future. The Company filed a request for rehearing on December 15, 2008 of the FERC’s decision, 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. The FERC suspended the period for ruling on the motion for rehearing on January 14, 2009. If the FERC denies the Company’s request for rehearing or again finds against the Company on rehearing, the Company will have the right to seek judicial review of the order. The Company cannot predict the outcome of such potential future proceedings.

On February 10, 2009, the FERC accepted a participation agreement submitted by nine WestConnect participants establishing the WestConnect Point-to-Point Regional Transmission Service Experiment (the “Proposal”). The FERC also conditionally accepted (subject to the participants making minor compliance filings) associated regional transmission tariffs that implement the Proposal for a two-year period. The Proposal calls for participants to offer customers the option of buying hourly non-firm, point-to-point transmission service across their collective transmission systems at a single rate. Taking coordinated service under the proposal is an alternative to pancaked point-to-point transmission service offered under each member’s individual Open Access Transmission Tariff. The Company does not expect participation in the Proposal to have a material impact on transmission revenues.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 D – Palo Verde – 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

C. Regulatory Assets and Liabilities

The Company’s operations are regulated by the Texas Commission, the NMPRC and the FERC. The provisions of SFAS No. 71 are applied to its regulated operations. 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, 2008		December 31, 2007
	Amortization Period Ends	December 31, 2008		December 31, 2007
Regulatory assets
New Mexico procurement plan costs	(a)	$	464	$	214
New Mexico loss on reacquired debt (b)	May 2030		5,585		5,525
New Mexico renewable energy credits	(a)		2,278		1,497
New Mexico rate case costs (b)	June 2010		294		476
New Mexico Palo Verde deferred depreciation (b)	(c)		1,713		549
New Mexico energy efficiency	(d)		231		90
New Mexico transition costs (b)	June 2010		575		1,150
Texas energy efficiency	(a)		986		—
Regulatory assets pursuant to SFAS No. 109 (e)	(c)		24,326		20,783
Final coal reclamation (e)	July 2016		9,682		9,952
Nuclear fuel postload daily financing charge	(d)		2,482		2,431

Total regulatory assets		$	48,616	$	42,667


Regulatory liabilities

Texas energy efficiency		$	–	$	281
Regulatory liabilities pursuant to SFAS No. 109 (e)	(c)		8,839		9,345
Accumulated deferred investment tax credit (f)	(c)		5,630		5,250

Total regulatory liabilities		$	14,469	$	14,876

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

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

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

(d)	This asset will be recovered through a recovery factor after expenses are incurred.

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

(f)	This item is excluded from rate base.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

D. 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, 2008 (in thousands):


	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	713,284	$	(185,663	)	$	527,621
Steam and other		289,270		(179,525	)		109,745

Total production		1,002,554		(365,188	)		637,366

Transmission		363,469		(222,024	)		141,445
Distribution		708,167		(259,030	)		449,137
General		117,752		(58,725	)		59,027
Intangible		31,124		(14,086	)		17,038

Total	$	2,223,066	$	(919,053	)	$	1,304,013

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 10 years). The amortization expense for intangible plant was $4.1 million, $3.3 million and $2.8 million for 2008, 2007 and 2006, respectively. The table below presents the estimated amortization expense for the next five years (in thousands):


2009	$	4,114
2010		3,763
2011		2,865
2012		2,407
2013		1,517

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.

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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, 2008 and 2007 is as follows (in thousands):


	December 31, 2008						December 31, 2007
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	713,284		$	201,746		$	660,342		$	193,574
Accumulated depreciation		(185,663	)		(153,960	)		(174,024	)		(147,203	)
Construction work in progress		34,851			5,054			75,035			5,051

Total	$	562,472		$	52,840		$	561,353		$	51,422

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. Based on this assessment information and using a cornerstone evaluation system, the NRC determines the appropriate level of agency response and oversight, including supplemental inspections and pertinent regulatory actions as necessary. The NRC has placed Palo Verde Unit 3 in the “multiple/repetitive degraded cornerstone” column of the NRC’s action matrix which has resulted in an enhanced NRC inspection regimen. This enhanced inspection regimen and resulting corrective actions has resulted in increased operating costs at the plant. Palo Verde is working to correct the issues identified by the NRC and to return to Column I, “licensee response” of the NRC’s action matrix. The Company is currently unable to predict the impact that the NRC’s increased oversight may have on Palo Verde’s future operations and the cost of operations.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

January 31, 1998. The DOE did not meet that deadline, and the Company cannot currently predict when spent fuel shipments to the DOE’s permanent disposal site will commence.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

E. Accounting for Asset Retirement Obligations

The Company complies with SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS No. 143”) and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). SFAS No. 143 primarily 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. FIN 47 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. Amounts recorded under SFAS No. 143, including those under FIN 47, are subject to various assumptions and determinations such as (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2007 Palo Verde decommissioning study. See Note D. 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. Since the Company assumed an escalation rate of 3.6% and a credit-risk adjusted discount rate of 9.5% in the original calculation of the ARO liability, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ARO liability is less than the Company’s share of the current estimated cost to decommission Palo Verde in 2007 dollars. 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 which are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2008 is $111.3 million.

SFAS No. 143 requires the Company to revise its previously recorded ARO for any changes in estimated cash flows. 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. Since the 2007 study reflected a downward revision in the estimated cash flows for decommissioning costs from the 2004 study, the Company recorded an $8.6 million reduction to its ARO asset and liability in the first quarter of 2008. Accretion and depreciation expense related to the ARO decreased approximately $1.3 million annually as a result of this adjustment.

A reconciliation of the Company’s ARO liability recorded is as follows (in thousands):


	2008			2007			2006
ARO liability at beginning of year	$	79,709		$	73,267		$	66,997
Liabilities incurred		—			—			—
Liabilities settled		—			(418	)		—
Revisions to estimate		(8,559	)		—			—
Accretion expense		6,887			6,860			6,270

ARO liability at end of year	$	78,037		$	79,709		$	73,267

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.

F. 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.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Incentive Plan

On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the “2007 Plan”) and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the plan, 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 these plans. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under SFAS No. 123 (revised).

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 2008:


	Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Term	Aggregate Intrinsic Value
					(In thousands)
Options outstanding at December 31, 2007	573,888	$	13.26
Options exercised	108,000		10.81

Options outstanding at December 31, 2008	465,888		13.83	3.00	$	1,983

Exercisable at December 31, 2008	465,888		13.83	3.00		1,983

The Company received approximately $1.2 million in cash for the 108,000 stock options exercised in 2008. During 2008, the Company realized $0.4 million in current tax benefits from the exercise of stock options. The intrinsic value of stock options exercised in 2008, 2007 and 2006 was $1.0 million, $5.2 million and $5.6 million, respectively. The fair value at grant date of options vested during 2008, 2007 and 2006 was $0.1 million, $0.8 million and $1.2 million, respectively. No options were forfeited or expired during 2008.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Shares		Weighted Average Grant Date Fair Value
Nonvested options at December 31, 2007	20,000		$	4.82
Options vested	(20,000	)		4.82

Nonvested options at December 31, 2008	—			—

On January 2, 2008, the remaining 20,000 stock options vested and at December 31, 2008 all 465,888 options outstanding had vested. No compensation cost was recognized in 2008 for stock options. The Company recorded compensation costs of less than $0.1 million and $0.8 million in 2007 and 2006, respectively, related to the outstanding unvested stock option awards. The tax benefit and capitalized costs related to these compensation costs in 2007 and 2006 were less than $0.1 million and $0.3 million, respectively. There is no remaining unrecognized compensation costs related to stock options.

Restricted Stock. The Company has awarded restricted stock under its long-term incentive plans. Restrictions from resale generally lapse and awards vest over periods of one to three years. The market value of vested restricted stock awards is expensed at the time of grant. 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.

Approximately $1.4 million, $1.7 million and $1.6 million was charged to expense related to restricted stock awards in 2008, 2007 and 2006, respectively. The deferred tax benefit related to these expenses was $0.5 million, $0.7 million and $0.6 million for 2008, 2007 and 2006, respectively. Current tax expense of $0.1 million was recognized by the Company in 2008 from the issuance of restricted stock. The Company realized $0.2 million and $0.1 million of current tax benefits from the issuance of restricted stock in 2007 and 2006, respectively. Any capitalized costs related to these expenses would be less than $0.1 million for all years.

The aggregate intrinsic value for restricted stock vested during 2008, 2007 and 2006 was $1.6 million, $2.0 million and $1.9 million, respectively. The fair value at grant date for restricted stock vested in 2008, 2007 and 2006 was $1.8 million, $1.4 million and $1.6 million, respectively. The outstanding restricted stock has remaining $1.4 million of unrecognized expense at December 31, 2008 that is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year. The aggregate intrinsic value of the 127,800 outstanding restricted shares at December 31, 2008 was $2.3 million.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the unvested restricted stock transactions for 2008:


	Total Shares		Weighted Average Grant Date Fair Value
Restricted shares outstanding at December 31, 2007	119,403		$	25.71
Restricted stock awards	117,550			20.05
Lapsed restrictions and vesting	(72,303	)		25.44
Forfeitures	(36,850	)		26.73

Restricted shares outstanding at December 31, 2008	127,800			20.37

The weighted average fair values at grant date for restricted stock awarded during 2008, 2007 and 2006 are $20.05, $26.39 and $19.85, respectively.

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and, if applicable, receive cash dividends on restricted stock, except that certain restricted stock awards require any cash dividend on restricted stock to be delivered to the Company in exchange for additional shares of restricted stock of equivalent market value.

Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plans, which provide 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. On January 1, 2008, 41,958 performance shares were issued at the 125% performance level with a total cost of $0.8 million which had been expensed ratably between 2005 and 2007. The Company realized $0.3 million of current tax benefits from the issuance of performance shares in 2008. The requisite service period for these shares ended December 31, 2007, and the shares had an aggregate intrinsic value of $1.1 million. Performance shares vesting on January 1, 2009 did not meet the minimum payout threshold and no shares were issued. On January 1, 2010 and 2011, subject to meeting certain performance criteria, performance shares could be awarded. In accordance with SFAS No. 123 (revised), the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. The actual number of shares issued can range from zero to 205,500 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

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 following table summarizes the outstanding performance share awards at the 100% performance level:


	Number Outstanding		Weighted Average Grant Date Fair Value
Performance shares outstanding at December 31, 2007	146,341		$	21.75
Performance share awards	68,900			17.14
Performance shares lapsed and issued	(33,567	)		22.55
Performance shares forfeited	(37,930	)		24.90

Performance shares outstanding at December 31, 2008	143,744			18.52

The outstanding performance awards have remaining $0.8 million of unrecognized expense at December 31, 2008 that is expected to be recognized over the weighted average remaining contractual term of the awards of approximately 1 year. The aggregate intrinsic value of the 143,744 outstanding awards (based on 100% performance level) at December 31, 2008 was $2.6 million. The weighted average per share grant date fair value of performance shares awarded during the years 2008, 2007 and 2006 was $17.14, $22.78, and $18.37, respectively. The fair value of performance shares which vested in 2008, 2007 and 2006 was $0.8 million, $0.7 million and $0.8 million, respectively, with an intrinsic value of $0.9 million, $1.0 million and $0.8 million, respectively.

The Company recorded compensation expense related to performance shares of $0.8 million in 2008 and $0.4 million in 2007 and 2006, respectively. The compensation expense for 2008 and 2007 included cumulative adjustments for forfeiture of performance share awards by certain executives. Compensation expense for 2006 included a cumulative adjustment to operating expense related to 2004 and 2005 performance stock awards to reflect the implementation of SFAS No. 123 (revised) which reduced expense by $0.7 million pretax and $0.4 million after-tax. Deferred tax expense related to compensation expense in 2008, 2007 and 2006 was $0.3 million, $0.1 million and less than $0.1 million, respectively.

Common Stock Repurchase Program

In November 2007, the Board authorized the repurchase of up to 2 million shares of the Company’s outstanding common stock (the “2007 Plan”). No shares remain available under previous plans. During 2008, 478,634 shares were repurchased at an aggregate cost of $9.9 million, including commissions, under the 2007 Plan. As of December 31, 2008, the Company had 1,521,366 shares authorized for repurchase under the 2007 Plan. Since the inception of the stock repurchase program in 1999, the Company has repurchased a total of approximately 19.8 million shares of its common stock at an aggregate cost of $279.3 million, including commissions. The Company may in the future make

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

purchases of its common stock pursuant to the 2007 Plan 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.

Reconciliation of Basic and Diluted Earnings Per Share

The reconciliation of basic and diluted earnings per share before extraordinary item is presented below:


	Year Ended December 31, 2008
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before extraordinary item	$	77,621	44,777,765	$	1.73

Effect of dilutive securities:
Unvested restricted stock		—	50,748
Unvested performance awards		—	15,820
Stock options		—	136,524

Diluted earnings per share:
Income before extraordinary item	$	77,621	44,980,857	$	1.73


	Year Ended December 31, 2007
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before extraordinary item	$	74,753	45,563,858	$	1.64

Effect of dilutive securities:
Unvested restricted stock		—	55,460
Unvested performance awards		—	69,426
Stock options		—	239,734

Diluted earnings per share:
Income before extraordinary item	$	74,753	45,928,478	$	1.63

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31, 2006
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before extraordinary item	$	61,387	47,663,890	$	1.29

Effect of dilutive securities:
Unvested restricted stock		—	57,459
Unvested performance awards		—	87,147
Stock options		—	355,571

Diluted earnings per share:
Income before extraordinary item	$	61,387	48,164,067	$	1.27

Performance shares of 122,479, 28,172 and 53,025 were excluded from the computation of earnings per share for the twelve months ended December 31, 2008, 2007 and 2006, respectively, as no payouts would be required based upon current performance. These amounts assume a 100% performance level payout. No options were excluded from the computation of diluted earnings per share because the exercise price was lower than the average market price for the years ended December 31, 2008, 2007 and 2006.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

G. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (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 Income (Loss)
Balance at December 31, 2005	$	4,468		$	(20,737	)	$	(13,898	)	$	(30,167	)
Other comprehensive income		9,466			16,923			263			26,652
Income tax expense		(1,893	)		(6,348	)		(99	)		(8,340	)
SFAS No. 158 adoption, net of tax of $3,879		—			(6,461	)		—			(6,461	)

Balance at December 31, 2006		12,041			(16,623	)		(13,734	)		(18,316	)
Other comprehensive income		4,152			41,256			278			45,686
Income tax expense		(830	)		(18,037	)		(104	)		(18,971	)
Adjustment for tax effect of SFAS No. 158		—			5,141			—			5,141

Balance at December 31, 2007		15,363			11,737			(13,560	)		13,540
Other comprehensive income (loss)		(26,903	)		(33,493	)		297			(60,099	)
Income tax (expense)		5,381			11,922			(108	)		17,195

Balance at December 31, 2008	$	(6,159	)	$	(9,834	)	$	(13,371	)	$	(29,364	)

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

H. Long-Term Debt and Financing Obligations

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


	December 31,
	2008			2007
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
2005 Series B refunding bonds, due 2040	$	63,500		$	63,500
4.80% 2005 Series A refunding bonds, due 2040		59,235			59,235
2005 Series C refunding bonds, due 2040		37,100			37,100
4.00% 2002 Series A refunding bonds, due 2032		33,300			33,300
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035		397,789			397,759
7.50% Senior Notes, net of discount, due 2038		148,728			—

Total long-term debt		739,652			590,894
Financing Obligations:
Nuclear fuel ($23,587 due in 2009) (3)		93,653			83,015

Total long-term debt and financing obligations		833,305			673,909
Current Portion (amount due within one year)		(23,587	)		(18,798	)

	$	809,718		$	655,111

(1)	Pollution Control Bonds (“PCBs”)

The Company has four series of tax exempt PCBs in an aggregate principal amount of approximately $193.1 million. The 2005 Series A $59.2 million bonds which mature in 2040, have a fixed interest rate of 4.80% and an effective interest rate of 5.27% after considering related insurance and issuance costs. The 2005 Series B $63.5 million and 2005 Series C $37.1 million bonds, which also mature in 2040, have a variable rate that is repriced weekly. Interest rates on the Series B and Series C bonds were 14.60% and 14.70% at December 31, 2008, respectively. These bonds are insured by Financial Guaranty Insurance Company (“FGIC”). The Company has experienced increased yields and resulting interest expense for the PCBs as a consequence of the current condition of the financial markets. Although there has not yet been a failed auction of the PCBs, if one were to occur the Company would be required to pay a default interest rate of 15%. The Company has obtained approval from the FERC and NMPRC to enter into securities transactions to refund and reissue these two series of PCBs to fix the interest rates. The 2002 Series A $33.3 million of pollution control

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

bonds bear a fixed interest rate of 4.00% until August 1, 2012 when the bonds are due to be remarketed. The effective interest rate for these bonds is 4.70% after considering related insurance and issuance costs. The interest rate will remain at its current fixed interest rate until remarketing in August 2012.

(2)	Senior Notes

The Company filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “SEC”) which became effective in May 2005 (the “2005 Shelf Registration Statement”). The shelf registration statement enabled the Company to offer and issue debt securities, first mortgage bonds, shares of stock and certain other securities from time to time in one or more offerings of up to $1.0 billion.

In May 2005, the Company issued $400.0 million aggregate principal amount of its 6% Senior Notes due May 15, 2035 under the 2005 Shelf Registration Statement. The proceeds from the issuance of the 6% Senior Notes of $397.7 million (net of a $2.3 million discount) were used to fund the retirement of the Company’s first mortgage bonds.

The Company filed an automatically-effective Shelf Registration Statement with the SEC on May 20, 2008 (the “WKSI Shelf Registration Statement”). This registration statement enables the Company to offer debt securities, first mortgage bonds, shares of stock and certain other securities in unspecific amounts from time to time in one or more offerings.

In June 2008, the Company issued $150.0 million aggregate principal amount of its 7.5% Senior Notes due March 15, 2038 under the WKSI Shelf Registration Statement. Proceeds from the issuance of the 7.5% Senior Notes of $148.7 million ($150 million principal amount net of a $1.3 million discount) were used to repay short-term borrowings of $44.0 million. The remaining proceeds will be used to fund capital expenditures and for other general corporate purposes. 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.

(3)	Nuclear Fuel and Working Capital Financing

The Company has available a $200 million credit facility for a five-year term ending April 2011. The credit facility was expanded under terms of the facility from $150 million to $200 million in July 2007 due to increased volatility in the nuclear fuel market. The credit facility provides for up to $120 million for the financing of nuclear fuel, which is accomplished through a trust that borrows under the facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest. In the Company’s financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company. Any amounts not borrowed by the trust

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

may be borrowed by the Company for working capital needs. The weighted average interest rate on the credit facility was 0.97% as of December 31, 2008.

The $200 million credit facility requires compliance with certain total debt and interest coverage ratios. The Company was in compliance with these requirements throughout 2008. No amounts were outstanding under this facility for working capital needs as of December 31, 2008.

As of December 31, 2008, the scheduled maturities for the next five years of long-term debt and financing obligations are as follows (in thousands):


2009	$	—
2010		—
2011		—
2012		33,300
2013		—

The table above does not reflect future obligations and maturities related to nuclear fuel financing obligations.

I. Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2008 and 2007 are presented below (in thousands):


	December 31,
	2008			2007
Deferred tax assets:
Alternative minimum tax credit carryforward	$	28,568		$	42,495
Pensions and benefits		52,730			40,860
Asset retirement obligation		27,313			27,898
Other		16,577			18,966

Total gross deferred tax assets		125,188			130,219

Deferred tax liabilities:
Plant, principally due to depreciation and basis differences		(245,267	)		(240,443	)
Decommissioning		(27,403	)		(33,896	)
Deferred fuel		(16,400	)		(9,694	)
Other		(16,143	)		(15,049	)

Total gross deferred tax liabilities		(305,213	)		(299,082	)

Net accumulated deferred income taxes	$	(180,025	)	$	(168,863	)

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 net deferred tax assets will be fully realized at current levels of book and taxable income.

The Company recognized income taxes as follows (in thousands):


	Years Ended December 31,
	2008		2007			2006
Income tax expense:
Federal:
Current	$	18,324	$	19,579		$	7,973
Deferred		15,525		10,499			27,496

Total federal income tax		33,849		30,078			35,469

State:
Current		3,242		4,496			1,007
Deferred		739		(107	)		(6,845	)

Total state income tax		3,981		4,389			(5,838	)

Total income tax expense		37,830		34,467			29,631

Tax expense classified as extraordinary gain on re-application of SFAS No. 71		—		—			(3,565	)

Total income tax expense before extraordinary item	$	37,830	$	34,467		$	26,066

Current federal income tax expense for 2008, 2007, and 2006 reflect taxes accrued under the alternative minimum tax (“AMT”). Deferred federal income tax for 2008 and 2007 includes an offsetting AMT benefit of $8.1 million and $7.1 million, respectively. Deferred federal income tax includes an offsetting AMT expense of $8.4 million for 2006. The reduction in deferred state income taxes in 2006 is a result of legislation approved in Texas revamping the state franchise (income) tax. The tax legislation changes the franchise tax from a tax based upon either taxable capital or taxable income to a 1% tax on taxable margins. The revised franchise tax was effective for tax payments in 2008 based upon 2007 taxable margin. The Company’s taxable margin is based upon revenues taxable for federal income tax purposes less cost of goods sold which includes all costs of producing electricity, but does not include post-production costs. Even with the lower tax rate, the expansion of the tax base resulted in higher franchise tax expense beginning in 2007.

For accounting purposes, the revised franchise tax is an income tax subject to the requirements of SFAS No. 109, “Accounting for Income Taxes”. SFAS No. 109 requires that deferred tax assets and liabilities be adjusted for changes in tax law in the period of change. As a result, the Company recorded a $6.2 million reduction in its net deferred tax liability in the second quarter of 2006 and a corresponding reduction in income tax expense. The adjustment to the net deferred income tax liability includes: (i) a reduction of $2.7 million in net Texas deferred income tax liabilities associated with temporary differences that will not reverse in the future under the revised franchise tax calculation; (ii) a reduction of $6.8 million in net Texas deferred income tax liabilities for the change in tax rate from 4.5% to 1%

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

effective in 2007; and (iii) an increase of $3.3 million in deferred federal income tax liabilities to reflect the change in deferred federal income taxes associated with deferred Texas franchise taxes.

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,
	2008			2007			2006
Federal income tax expense computed on income at statutory rate	$	40,408		$	38,227		$	33,938
Difference due to:
State taxes, net of federal benefit		2,588			2,852			2,184
Deferred tax adjustment for change in Texas franchise (income) tax		—			—			(6,174	)
Allowance for equity funds used during construction		(2,690	)		(2,398	)		—
Permanent tax differences		(1,935	)		(4,091	)		(1,670	)
Other		(541	)		(123	)		1,353

Total income tax expense		37,830			34,467			29,631
Tax expense classified as extraordinary gain on re-application of SFAS No. 71		—			—			(3,565	)

Total income tax expense before extraordinary item	$	37,830		$	34,467		$	26,066

Effective income tax rate		32.8	%		31.6	%		31.0	%

As of December 31, 2008, the Company had $28.6 million of AMT credit carryforwards that have an unlimited life.

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 2005 and in the state jurisdictions for years prior to 1998. The Company’s federal tax returns are currently under audit for 2005 and 2006. On August 14, 2008, the Company reached a settlement with the IRS for tax years 1999 through 2004. In the settlement of the tax years 1999 through 2004, the Company and the IRS agreed to (i) the deduction in the year incurred of 40% of payments related to the repair of the Palo Verde Unit 2 steam generator and the capitalization and depreciation of the remaining 60% of those payments (ii) the capitalization and depreciation of payments related to the dry cask storage facilities for spent nuclear fuel and (iii) the exclusion from taxable income of capital costs paid by third parties for construction of a switchyard. The IRS settlement affected the timing of these deductions but not their ultimate deductibility for federal tax purposes. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in Arizona contests a pollution control credit and the payroll apportionment factor. The Company is contesting these adjustments.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” (“FIN 48”) on January 1, 2007. FIN 48 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. As a result of the implementation of FIN 48, the Company recognized a $1.9 million decrease in the liability for unrecognized tax benefits, which was accounted for as an increase to the January 1, 2007, balance of retained earnings. A reconciliation of the December 31, 2007 and December 31, 2008 amount of unrecognized tax benefits is as follows (in millions):


	2008			2007
Balance at January 1	$	8.5		$	6.8
Additions/(reductions) based on tax positions related to the current year		(0.7	)		2.0
Additions for tax positions of prior years		2.6			0.1
Reductions for tax positions of prior years		(0.3	)		(0.4	)
Reductions for IRS settlement		(9.6	)		—

Balance at December 31	$	0.5		$	8.5

The Company has determined that the ultimate deductibility of the federal tax positions as of December 31, 2008 are “highly certain”, as such term is defined in FIN 48, but the timing of such deductibility is uncertain. Because of the impact of deferred tax accounting, the disallowance of the shorter deductibility period does not change the amount of tax expense other than associated interest and penalties. However, the timing of cash payments to the federal taxing authority would be affected. An unrecognized tax position of $0.5 million associated with state income taxes has been recognized as an increase in income tax expense.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the year ended December 31, 2008, the Company recognized a benefit of approximately $0.9 million in interest. For 2007 and 2006, the Company recognized expense of approximately $0.7 million and $0.1 million, respectively, in interest. The Company had approximately $0.5 million and $2.5 million for the payment of interest and penalties accrued at December 31, 2008 and December 31, 2007, respectively.

J. Commitments, Contingencies and Uncertainties

Federal Regulatory Matters

See Note B – Federal Regulatory Matters – Transmission Dispute with Tucson Electric Power Company, for discussion of FERC’s initial decision finding in the Company’s transmission dispute with TEP.

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Power Contracts

The Company had entered into the following significant agreements with various counterparties for forward firm purchases and sales of electricity:


Type of Contract	Quantity	Term
Power Purchase and Sale Agreement	100 MW (1)	2006 through 2021
Purchase Capacity	133 MW	2006 through September 2009
Power Sale Agreement	100 MW	May 2007 through April 2010
Power Purchase Agreement	100 MW	May 2007 through April 2010

(1)	Purchase agreement modified in 2008 to allow purchase of 125 MW from December 2008 through December 2010.

100

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.

Environmental Matters

101

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Another way in which environmental matters may impact the Company’s operations and business is the implementation of the U.S. Environmental Protection Agency’s (“EPA”) Clean Air Interstate Rule (“CAIR”) which, as applied to the Company, may result in a requirement that it substantially reduce emissions of nitrogen oxides from its power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. These requirements become more stringent in 2015, and are anticipated to require even further emissions reductions or additional allowance purchases. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR in its entirety. On December 23, 2008 the DC Circuit Panel granted Rehearing and issued its decision; it remanded CAIR without vacating the original statute. The Company will have to comply with CAIR as written until the EPA rewrites the CAIR as required by the court’s earlier opinion.

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


	Years Ended December 31,
	2008		2007		2006
Clean Air Act	$	584	$	1,808	$	1,203
Clean Water Act (1)		1,243		1,293		2,004

(1)	Includes a $0.2 million reserve for remediation costs for the Gila River Boundary Site discussed below for the twelve months ended December 31, 2008. For 2007 a $0.5 million adjustment was recorded reducing the estimated costs of remediation at the Rio Grande and Copper generating stations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On September 30, 2008, the State of New Mexico, acting on behalf of the New Mexico Environment Department (“NMED”), filed a complaint in New Mexico district court alleging that, on approximately 650 occasions between May 2000 and September 2005, the Company’s Rio Grande Generating Station, located in Dona Ana County, New Mexico, emitted sulfur dioxide, nitrogen oxides or carbon monoxide in excess of its permitted emission rates, and failed to properly report these allegedly excess emissions. These allegations were previously made by the NMED in a previously disclosed compliance order, which the NMED withdrew on September 30, 2008. On October 27, 2008, the State of New Mexico amended its complaint to allege approximately 300 additional exceedances of permitted nitrogen dioxide and carbon monoxide emission rates and associated reporting failures between October 2005 and July 2007. The amended complaint seeks civil penalties in the amount of $15,000 per day for each alleged violation. The Company’s motion to dismiss was denied, and the Company is preparing a response to the allegations. While the Company cannot predict the outcome of this suit, it believes these emissions did not violate applicable legal standards.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MiraSol Warranty Obligations

MiraSol is an energy services subsidiary which offered a variety of services to reduce energy use and/or lower energy costs. MiraSol was not a power marketer. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. In September 2008, a contract was renegotiated with a MiraSol customer resolving all liabilities. As a result of the resolution of all claims, the Company reversed $0.9 million of accrued warranty costs. Accruals, charges and balances for the reserve for warranty claims are as follows:


	Years Ended December 31,
	2008			2007			2006
Balance at beginning of year	$	985		$	1,785		$	1,288
Accrual of warranty costs		—			—			500
Charges for work performed		—			—			(3	)
Liabilities reversed/settled		(985	)		(800	)		—

Balance at end of year	$	—		$	985		$	1,785

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

While no other probable warranty liabilities have been identified at this time, if it is determined at a future date that MiraSol has further obligations to any customer, and contributions from MiraSol, its subcontractors or any other third party are insufficient to honor the warranty obligations, the Company intends to honor any such warranty obligations after making appropriate regulatory filings, if any.

Lease Agreements

The Company leased its general administrative offices in El Paso, Texas under a lease agreement with an 11-year term ending May 31, 2018 and fixed minimum lease payments of $1.7 million annually. On February 8, 2008, the Company exercised its right of first refusal in the lease agreement to purchase this office building. All obligations previously incurred relating to this lease were terminated.

In June 2008, the Company entered into an agreement to lease land adjacent to the Newman Power Station. The land lease expires in June 2033 and has an automatic renewal for an additional 25-year term.

The Company also leases warehouse facilities with a term expiring in December 2009 with three concurrent renewal options of one year each. The lease payments are $0.3 million annually. 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, $2.0 million and $1.7 million for 2008, 2007 and 2006, respectively. As of December 31, 2008, the Company’s minimum future rental payments for the next five years are as follows (in thousands):


2009	$	2,004
2010		523
2011		465
2012		426
2013		422

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

K. Litigation

See “Note B” for discussion of the effects of government legislation and regulation on the Company.

L. 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 income plans that are non-funded defined benefit plans. One plan covers certain former employees of the Company, and the other plan, an excess benefit plan adopted during 2004, covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement income plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan. On December 31, 2006, the Company adopted SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”, which amended SFAS No. 87 and SFAS No. 132R.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	December 31,
	2008						2007
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Change in projected benefit obligation:
Benefit obligation at end of prior year	$	180,301		$	20,397		$	182,222		$	22,112
Service cost		4,958			117			5,455			179
Interest cost		11,357			1,243			10,794			1,263
Actuarial loss (gain)		8,158			456			(12,153	)		(1,534	)
Benefits paid		(6,246	)		(1,658	)		(6,017	)		(1,623	)

Benefit obligation at end of year		198,528			20,555			180,301			20,397

Change in plan assets:
Fair value of plan assets at end of prior year		169,028			–			146,425			–
Actual return on plan assets		6,590			–			16,620			–
Employer contribution		9,000			1,658			12,000			1,623
Benefits paid		(6,246	)		(1,658	)		(6,017	)		(1,623	)

Fair value of plan assets at end of year		178,372			–			169,028			–

Funded status at end of year	$	(20,156	)	$	(20,555	)	$	(11,273	)	$	(20,397	)

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


	December 31,
	2008						2007
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Current liabilities	$	–		$	(1,610	)	$	–		$	(1,582	)
Noncurrent liabilities		(20,156	)		(18,945	)		(11,273	)		(18,815	)

Total	$	(20,156	)	$	(20,555	)	$	(11,273	)	$	(20,397	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accumulated benefit obligation for all retirement plans was $185.7 million and $164.7 million at December 31, 2008 and 2007, respectively. The accumulated benefit obligation in excess of plan assets is as follows (in thousands):


	December 31,
	2008						2007
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Projected benefit obligation	$	(198,528	)	$	(20,555	)	$	(180,301	)	$	(20,397	)
Accumulated benefit obligation		(165,912	)		(19,787	)		(149,308	)		(15,352	)
Fair value of plan assets		178,372			—			169,028			—

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


	Years Ended December 31,
	2008				2007
	Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans
Net loss	$	39,333	$	2,944	$	24,603	$	2,589
Prior service cost		89		691		110		785

Total	$	39,422	$	3,635	$	24,713	$	3,374

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


	December 31,
	2008						2007
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Retirement Income Plan		Excess Benefit Plan		Retirement Income Plan		Retirement Income Plan		Excess Benefit Plan
Discount rate	6.10	%	6.30	%	6.30	%	6.40	%	6.10	%	6.40	%
Rate of compensation increase	5.00	%	N/A		5.00	%	5.00	%	N/A		5.00	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2008					2007					2006
	Retirement Income Plan			Non- Qualified Retirement Income Plans		Retirement Income Plan			Non- Qualified Retirement Income Plans		Retirement Income Plan			Non- Qualified Retirement Income Plans
Service cost	$	4,958		$	117	$	5,455		$	179	$	5,466		$	141
Interest cost		11,357			1,243		10,794			1,263		9,892			1,236
Expected return on plan assets		(14,233	)		–		(12,537	)		–		(11,029	)		–
Amortization of:
Net loss		1,072			101		3,161			257		4,202			299
Prior service cost		21			94		21			94		22			94

Net periodic benefit cost	$	3,175		$	1,555	$	6,894		$	1,793	$	8,553		$	1,770

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


	Years Ended December 31,
	2008						2007						2006
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans

Net loss (gain)	$	15,802		$	456		$	(16,236	)	$	(1,533	)
Amortization of:
Net loss		(1,072	)		(101	)		(3,161	)		(257	)
Prior service cost		(21	)		(94	)		(21	)		(94	)
Increase (decrease) in minimum liability included in other comprehensive income before adoption of SFAS No. 158		—			—			—			—		$	(16,363	)	$	(560	)
Increase (decrease) in accumulated other comprehensive income due to adoption of SFAS No. 158		—			—			—			—			30,785			1,781

Total expense (income) recognized in other comprehensive income	$	14,709		$	261		$	(19,418	)	$	(1,884	)	$	14,422		$	1,221

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2008				2007						2006
	Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan		Non- Qualified Retirement Income Plans
Total recognized in net periodic benefit cost and other comprehensive income	$	17,884	$	1,816	$	(12,524	)	$	(91	)	$	22,975	$	2,991

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2009 (in thousands):

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost at December 31:


	2008						2007						2006
			Non-Qualified						Non-Qualified						Non-Qualified
	Retirement Income Plan		Retirement Income Plan		Excess Benefit Plan		Retirement Income Plan		Retirement Income Plan		Excess Benefit Plan		Retirement Income Plan		Retirement Income Plan		Excess Benefit Plan
Discount rate	6.40	%	6.10	%	6.40	%	5.90	%	5.70	%	5.90	%	5.50	%	5.50	%	5.50	%
Expected long-term return on plan assets	8.50	%	N/A		N/A		8.50	%	N/A		N/A		8.50	%	N/A		N/A
Rate of compensation increase	5.00	%	N/A		5.00	%	5.00	%	N/A		5.00	%	5.00	%	N/A		5.00	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. The Company changed its discount rate to determine the benefit obligations for the retirement income plan from 6.40% to 6.10%, the non-qualified retirement income plan from 6.10% to 6.30%; and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the excess benefit plan from 6.40% to 6.30% at December 31, 2008. For determining 2008 benefit costs, the Company changed its discount rate for the retirement income plan and the excess benefit plan from 5.90% to 6.40% and the non-qualified retirement income plan from 5.70% to 6.10%. A 1.0% decrease in the discount rate would increase the 2008 retirement plans’ projected benefit obligation by 14.7%. A 1.0% increase in the discount rate would decrease the 2008 retirement plans’ projected benefit obligation by 12.0%.

The Company’s overall expected long-term rate of return on assets is 8.50%, 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 Retirement Plan fund includes a diversified portfolio of mutual funds investing in equity securities including large and small capital funds, international funds, and an energy industry specific fund. The Retirement Plan fund also invests in fixed income securities and real estate. The expected returns for mutual 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.

The Company’s Retirement Plan fund actual asset allocation and target asset allocation are as follows:


	December 31,
	2008				2007
Asset Category	Actual		Target		Actual		Target
Equity funds	32	%	50	%	60	%	60	%
Fixed income	59		35		40		35
Alternative investments	9		15		–		5

Total	100	%	100	%	100	%	100	%

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 Employee Retirement Income Security Act of 1974 (ERISA) and Department of Labor (DOL) regulations.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 $6.3 million to its retirement plans in 2009, although the Company has no 2009 minimum funding requirements for the Retirement Plan.

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


	Retirement Income Plan		Non- Qualified Retirement Income Plans
2009	$	6,919	$	1,610
2010		7,496		1,585
2011		8,169		1,556
2012		8,961		1,530
2013		9,816		1,579
2014-2018		65,262		8,615

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 based on the funding amounts established in Texas Commission Docket No. 12700. 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 Staff Position No. 106-2 “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.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,
	2008			2007
Change in benefit obligation:
Benefit obligation at end of prior year	$	98,612		$	113,933
Service cost		3,160			3,870
Interest cost		6,199			6,053
Actuarial loss (gain)		5,439			(22,801	)
Benefits paid		(3,080	)		(2,810	)
Retiree contributions		535			367
Medicare Part D subsidy		171			—

Benefit obligation at end of year		111,036			98,612

Change in plan assets:
Fair value of plan assets at end of prior year		31,227			28,498
Actual return on plan assets		(7,036	)		1,750
Employer contribution		3,422			3,422
Benefits paid		(3,080	)		(2,810	)
Retiree contributions		535			367
Medicare Part D subsidy		171			—

Fair value of plan assets at end of year		25,239			31,227

Funded status	$	(85,797	)	$	(67,385	)

Amounts recognized in the Company’s consolidated balance sheets as a non-current liability consist of accrued postretirement costs of $85.8 million and $67.4 million for 2008 and 2007, respectively.

On December 31, 2006, the Company adopted SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”, which amended SFAS No. 106 and SFAS No. 132R.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amounts recognized in accumulated other comprehensive income that have not been recognized as a component of net periodic cost in accordance with SFAS No. 158 consist of the following (in thousands):


	Years Ended December 31,
	2008			2007
Net gain	$	(7,950	)	$	(23,604	)
Prior service credit		(15,708	)		(18,577	)

	$	(23,658	)	$	(42,181	)

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


	2008		2007
Discount rate at end of year	6.00	%	6.50	%
Trend rates:
Initial	9.00	%	9.50	%
Ultimate	5.00	%	5.00	%
Years ultimate reached	9		10

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


	Years Ended December 31,
	2008			2007			2006
Service cost	$	3,160		$	3,870		$	4,584
Interest cost		6,199			6,053			5,762
Expected return on plan assets		(1,853	)		(1,695	)		(1,478	)
Amortization of:
Prior service benefit		(2,869	)		(2,869	)		(2,869	)
Net gain		(1,325	)		(32	)		—

Net periodic benefit cost	$	3,312		$	5,327		$	5,999

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2008		2007			2006
Net loss (gain)	$	14,329	$	(22,856	)
Amortization of:
Prior service benefit		2,869		2,869
Net gain		1,325		32
Increase (decrease) in accumulated other comprehensive income due to adoption of SFAS No. 158		—		—		$	(22,226	)

Total recognized in other comprehensive income	$	18,523	$	(19,955	)	$	(22,226	)

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


	Years Ended December 31,
	2008		2007			2006
Total recognized in net periodic benefit cost and other comprehensive income	$	21,835	$	(14,628	)	$	(16,227	)

The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2009 is a prior service benefit of $2.9 million.

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost:


	2008		2007		2006
Discount rate at beginning of year	6.50	%	5.90	%	5.50	%
Expected long-term return on plan assets	5.90	%	5.90	%	5.90	%
Trend rates:
Initial	9.50	%	9.60	%	9.60	%
Ultimate	5.00	%	6.00	%	6.00	%
Years ultimate reached	10		4		4

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is evaluated at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. At December 31, 2008, the Company changed its discount rate from 6.50% to 6.00% for the

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

other postretirement benefits plan. For determining 2008 benefit cost, the Company changed its discount rate from 5.90% to 6.50%. A 1.0% decrease in the discount rate would increase the 2008 accumulated postretirement benefit obligation by 16.5%. A 1.0% increase in the discount rate would decrease the 2008 accumulated postretirement benefit obligation by 13.2%.

For measurement purposes, a 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2008. The rate was assumed to decrease gradually to 5% for 2017 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 benefit obligation by $18.0 million or $14.6 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of the net periodic benefit cost by $1.7 million or $1.3 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.90%. 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 asset portfolio includes a diversified mix of mutual funds investing in equity securities including large and small capital funds, international funds, and an energy industry specific fund. The asset portfolio also includes fixed income securities, cash equivalents, and real estate. The expected returns for mutual 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. The Company’s asset portfolio actual and target long-term asset allocations are as follows:


	December 31,
	2008				2007
Asset Category	Actual		Target		Actual		Target
Equity funds	54	%	55	%	70	%	65	%
Fixed income	33		30		30		30
Alternative investments	13		15		—		5

Total	100	%	100	%	100	%	100	%

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company expects to contribute $3.4 million to its other postretirement benefits plan in 2009.

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


	Including Medicare Part D Subsidy		Excluding Medicare Part D Subsidy		Reduction due to the Medicare Part D Subsidy
2009	$	3,222	$	3,478	$	(256	)
2010		3,735		4,023		(288	)
2011		4,288		4,614		(326	)
2012		4,870		5,239		(369	)
2013		5,473		5,894		(421	)
2014-2018		36,381		39,526		(3,145	)

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. Total matching contributions made to the savings plans for the years 2008, 2007 and 2006 were $1.6 million, $1.6 million and $1.5 million, respectively.

Annual Short-Term Bonus Plan

The Annual Short-Term Bonus Plan (the “Bonus 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 and customer satisfaction. If a certain level of earnings per share is not attained, no bonuses will be paid under the Bonus Plan. The Company reached the required levels of earnings per share, customer satisfaction, safety goals to pay bonuses of $5.2 million, $7.0 million and $6.1 million for 2008, 2007 and 2006, respectively. The Company has renewed the Bonus Plan in 2009 with similar goals.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

M. Franchises and Significant Customers

El Paso Franchise

Las Cruces Franchise

Military Installations

N. Financial Instruments and Investments

SFAS No. 107, “Disclosure about Fair Value of Financial Instruments,” 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 and financing obligations, 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 market value.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair values of the Company’s long-term debt and financing obligations, including the current portion thereof, are based on estimated market prices for similar issues and are presented below (in thousands):


	December 31,
	2008				2007
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Pollution Control Bonds	$	193,135	$	168,735	$	193,135	$	192,820
Senior Notes		546,517		423,042		397,759		376,150
Nuclear Fuel Financing (1)		93,653		93,653		83,015		83,015

Total	$	833,305	$	685,430	$	673,909	$	651,985

(1)	The interest rate on the Company’s financing for nuclear fuel purchases is reset every quarter to reflect 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 2009, approximately $0.3 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, 2008, 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 SFAS No. 133, and, as such, were not required to be accounted for as derivatives pursuant to SFAS No. 133 and other guidance.

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 SFAS No. 133. However, as of December 31, 2008, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.

119

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $111.3 million and $130.7 million at December 31, 2008 and 2007, respectively. These securities are classified as available for sale under SFAS No. 115 “Accounting 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, at December 31, 2008 and 2007 (in thousands):


	December 31, 2008
	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	$	—	$	—		$	88	$	(3	)	$	88	$	(3	)
Municipal Obligations		8,656		(227	)		5,201		(137	)		13,857		(364	)
Corporate Obligations		2,302		(249	)		1,548		(163	)		3,850		(412	)

Total debt securities		10,958		(476	)		6,837		(303	)		17,795		(779	)

Common stock		21,179		(6,431	)		604		(204	)		21,783		(6,635	)
Mutual Funds		7,152		(3,539	)		—		—			7,152		(3,539	)

Total equity securities		28,331		(9,970	)		604		(204	)		28,935		(10,174	)

Total temporarily impaired securities	$	39,289	$	(10,446	)	$	7,441	$	(507	)	$	46,730	$	(10,953	)

(1)	Includes approximately 161 securities.


	December 31, 2007
	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	$	944	$	(2	)	$	2,253	$	(34	)	$	3,197	$	(36	)
Municipal Obligations		3,072		(11	)		6,995		(54	)		10,067		(65	)
Corporate Obligations		1,119		(24	)		880		(10	)		1,999		(34	)

Total debt securities		5,135		(37	)		10,128		(98	)		15,263		(135	)
Common stock		9,031		(1,464	)		—		—			9,031		(1,464	)

Total temporarily impaired securities	$	14,166	$	(1,501	)	$	10,128	$	(98	)	$	24,294	$	(1,599	)

(2)	Includes approximately 80 securities.

120

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 original 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 2024 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 at December 31, 2008 and 2007 (in thousands):


	December 31, 2008				December 31, 2007
	Fair Value		Unrealized Gains		Fair Value		Unrealized Gains
Description of Securities:
Federal Agency Mortgage Backed Securities	$	13,122	$	382	$	7,898	$	71
U.S. Government Bonds		3,147		367		4,904		182
Municipal Obligations		19,088		506		21,294		359
Corporate Obligations		1,021		69		2,005		63

Total debt securities		36,378		1,324		36,101		675

Common stock		25,123		2,046		55,995		18,032
Mutual Funds		—		—		11,601		2,212

Total equity securities		25,123		2,046		67,596		20,244
Temporary investments		3,075		—		2,663		—

Total	$	64,576	$	3,370	$	106,360	$	20,919

The Company’s marketable securities include investments in municipal debt obligations and corporate debt obligations. The contractual year for maturity of these available-for-sale securities as of December 31, 2008 is as follows (in thousands):


	Total		2009		2010 through 2013		2014 through 2018		2019 and Beyond
Municipal Debt Obligations	$	32,945	$	1,202	$	11,529	$	12,608	$	7,606
Corporate Debt Obligations		4,871		228		1,427		2,600		616
U.S. Government Bonds and Federal Agency Mortgage Backed Securities		16,357		—		1,404		1,126		13,827

The Company has recognized some impairment losses on certain of its securities to be other than temporary and in accordance with SFAS No. 115 these impairment losses have been recognized in net income and a lower cost basis has been established for these securities. For the twelve months ended

121

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2008, 2007, and 2006 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):


	2008			2007		2006
Gross unrealized holding losses included in pre-tax income	$	(7,761	)	$	—	$	(512	)

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, 2008, 2007, and 2006 and the related effects on pre-tax income are as follows (in thousands):


	2008			2007			2006
Proceeds from sales of available-for-sale securities	$	53,447		$	105,201		$	98,085

Gross realized gains included in pre-tax income	$	5,505		$	2,639		$	1,642
Gross realized losses included in pre-tax income		(2,214	)		(1,777	)		(2,635	)
Net unrealized gains (losses) in pre-tax income		(6,167	)		821			332

Net gains (losses) in pre-tax income	$	(2,876	)	$	1,683		$	(661	)

Net unrealized holding gains (losses) included in accumulated other comprehensive income	$	(29,779	)	$	5,835		$	8,805
Net (gains) losses reclassified out of accumulated other comprehensive income		2,876			(1,683	)		661

Net gains (losses) in other comprehensive income	$	(26,903	)	$	4,152		$	9,466

Fair Value Measurements. The Company adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) during the first quarter of 2008. SFAS No. 157 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. The Company has no liabilities that are measured at fair value on a recurring basis. To increase consistency and comparability in fair value measurements, this new standard 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 transparent market.

122

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

•

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 other 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.

As of December 31, 2008, the Company had $4.0 million invested in debt securities which consisted of two $2.0 million investments in auction rate securities maturing in 2042 and 2044. The Company classifies them as trading securities. These auction rate securities are collateralized with student loans which are re-insured by the Department of Education as part of the Federal Family Education Loan Program (“FFELP”) and have a credit rating of “A” by Standards & Poors and “A2” by Moody’s. The principal on the securities can be realized at maturity, sold in a successful auction, or sold in the secondary market. Interest rates on the auction rate securities are reset every 28 days. Upon a failed auction the maximum interest rates are based upon LIBOR plus 1.0% – 2.5% with rate limitations based upon interest rates on the underlying student loans. At December 31, 2008, the maximum interest rates were 2.081% to 2.971%.

The auction process historically provided a liquid market to sell the securities to meet cash requirements. These auction rate securities had successful auctions through January 2008. However, beginning in February 2008, auctions for these securities have not been successful, resulting in the inability to liquidate these investments. The Company’s valuation as of December 31, 2008 is based upon the average of a discounted cash flow model valuation and a market comparables method.

The discounted cash flow model valuation is based on expected cash flows using the maximum expected interest rates discounted by an expected yield reflecting illiquidity. In order to more accurately forecast cash flows, treasury and swap curves were created using data provided on the U.S. Department of the Treasury website and the British Banker’s Association website. After thorough analysis, future cash flows were projected based on interest rate models over a term, which was based on an estimate of the weighted average life of the student loan portfolio within the issuing trusts. The applied discount yield was based on the applicable forward LIBOR rate and a yield spread of 650 basis points based on the securities’ (i) credit risk, (ii) illiquidity, (iii) subordinated status, (iv) interest rate limitations, and (v) FFELP guarantees.

The market comparables method is based upon sales and purchases of auction rate securities in secondary market transactions. The average secondary market discount on comparable Student Loan Auction Rate Securities taking into account the specific characteristics of the securities was 40%. The

123

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

average of the values provided by the discounted cash flow calculation and the market comparables method are used to arrive at the concluded value of the 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. SFAS No. 157 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. In 2008, $6.2 million of impairments deemed to be other than temporary were recognized in the consolidated statement of operations. There were no impairments recognized in the statement of operations in 2007.

The fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2008, and the level within the three levels of the fair value hierarchy defined by SFAS No. 157 are presented in the table below (in thousands):


Description of Securities	Fair Value as of December 31, 2008		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	$	2,264	$	—	$	—	$	2,264


Available for sale:
U.S. Government Bonds	$	3,147	$	3,147	$	—	$	—
Federal Agency Mortgage Backed Securities		13,210		—		13,210		—
Municipal Bonds		32,945		—		32,945		—
Corporate Asset Backed Obligations		4,871		—		4,871		—

Subtotal, Debt Securities		54,173		3,147		51,026		—


Common Stock		46,906		46,906		—		—
Mutual Funds		7,152		7,152		—		—

Subtotal, Equity Securities		54,058		54,058		—		—


Cash and Cash Equivalents		3,075		3,075		—		—

Total available for sale	$	111,306	$	60,280	$	51,026	$	—

124

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the investments in debt securities as of December 31, 2008 resulted in a charge to income of $1.7 million for the twelve months ended December 31, 2008 and is reflected in the Company’s consolidated statement of operations as a reduction to investment and interest income. The table below reflects the changes during the period (in thousands):


	Fair Value of Investments in Debt Securities
Balance at December 31, 2007	$	—
Transfers into Level 3 (1)		4,000
Unrealized loss in fair value recognized in income		(1,736	)

Balance at December 31, 2008	$	2,264

(1)	Amounts presented as being transferred in are based on the fair value at the beginning of the period.

125

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

O. Supplemental Statements of Cash Flows Disclosures


	Years Ended December 31,
	2008		2007		2006
	(In thousands)
Cash paid for:
Interest on long-term debt and financing obligations	$	41,909	$	34,146	$	33,302
Income taxes		4,353		26,312		5,666
Other interest		196		—		—
Non-cash financing activities:
Grants of restricted shares of common stock		3,021		3,502		1,529
Deferred tax benefit on long-term incentive plans		43		3,993		954

126

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

P. Selected Quarterly Financial Data (Unaudited)


	2008 Quarters								2007 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
	(In thousands except for share data)
Operating revenues (1)	$	212,486	$	301,799	$	284,405	$	240,240	$	211,194	$	258,525	$	219,291	$	188,417
Operating income		21,948		59,753		34,809		29,226		15,971		60,990		21,451		29,909
Net income (2)		10,825		33,074		19,234		14,488		13,947		36,088		9,599		15,119
Basic earnings per share:
Net income		0.24		0.74		0.43		0.32		0.31		0.79		0.21		0.33
Diluted earnings per share:
Net income		0.24		0.74		0.43		0.32		0.30		0.79		0.21		0.33

(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.

(2)	During the fourth quarter of 2007, net income was positively affected by $4.0 million of deferred income tax adjustments related to earlier quarters and the reversal of a $1.4 million reserve for rate refund upon completion of contract negotiations with a large Texas customer.

(3)	Net income in the fourth quarter of 2008 was reduced by a $2.5 million refund of 2006 transmission wheeling revenues from Tucson Electric Power pursuant to an order of the FERC.

127

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 have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and its subsidiaries is communicated to the chief executive officer and the chief financial officer by others within those entities. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2008, our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the chief executive officer and the chief financial officer, and recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

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 55 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, 2008, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

None.

128

PART III

Item 10.

Directors and Executive Officers of the Registrant

Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2009 Annual Meeting of Shareholders (the “2009 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 2009 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 2009 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 2009 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 2009 Proxy Statement under the caption “Business Conduct Policies” under the heading “Corporate Governance.”

Item 11.

Executive Compensation

Incorporated herein by reference from the 2009 Proxy Statement under the heading “Summary of Compensation.”

Item 12.

Security Ownership of Certain Beneficial Owners and Management

Incorporated herein by reference from the 2009 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”

129

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	465,888	$	13.83	1,013,953
Equity compensation plans not approved by security holders	—		—	—

Total	465,888	$	13.83	1,013,953

Item 13.

Certain Relationships and Related Transactions

Incorporated herein by reference from the 2009 Proxy Statement under the heading “Certain Relationships and Related Party Transactions.”

Item 14.

Principal Accounting Fees and Services

Incorporated herein by reference from the 2009 Proxy Statement under the heading “Independent Registered Public Accounting Firm.”

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	56

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.

130

INDEX TO EXHIBITS


Exhibit Number	Title
Exhibit 3 – Articles of Incorporation and Bylaws:

3.01	–	Restated Articles of Incorporation of the Company, dated February 7, 1996 and effective February 12, 1996. (Exhibit 3.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

3.02	–	Bylaws of the Company, dated February 6, 1996. (Exhibit 3.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

Exhibit 4 – Instruments Defining the Rights of Security Holders, including Indentures:

4.01	–	General Mortgage Indenture and Deed of Trust, dated as of February 1, 1996, and First Supplemental Indenture, dated as of February 1, 1996, including form of Series A through H First Mortgage Bonds. (Exhibit 4.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

4.01-01	–	Second Supplemental Indenture, dated as of August 19, 1997, to Exhibit 4.01. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1997)

4.01-02	–	Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01. (Exhibit 4.01-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004)

4.01-03	–	Sixth Supplemental Indenture to Exhibit 4.01, dated as of May 5, 2005 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)

4.02	–	Reserved

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)

131

INDEX TO EXHIBITS


Exhibit Number	Title
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 of California, N.A. as Trustee dated as of July 1, 2005 relating to $63,500,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2005 Series B (El Paso Electric Company Palo Verde Project). (Exhibit 4.33 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.07	–	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 4.06. (Exhibit 4.34 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.08	–	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 $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2005 Series C (El Paso Electric Company Palo Verde Project). (Exhibit 4.35 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.09	–	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 4.08. (Exhibit 4.36 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

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 Exhibits 4.03, 4.06 and 4.08. (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 Exhibits 4.03, 4.06 and 4.08. (Exhibit 4.38 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

132

INDEX TO EXHIBITS


Exhibit Number	Title
4.12	–	Broker-Dealer Agreement dated August 1, 2005 among The Bank of New York, as Auction Agent, Citigroup Global Markets Inc., as Broker-Dealer and El Paso Electric Company, as Borrower, relating to the Pollution Control Bonds referred to in Exhibits 4.06 and 4.08. (Exhibit 4.39 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.13	–	Auction Agent Agreement dated as of August 1, 2005 among El Paso Electric Company and Union Bank of California, N.A., as Trustee and The Bank of New York, as Auction Agent, relating to the Pollution Control Bonds referred to in Exhibits 4.06 and 4.08. (Exhibit 4.40 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.14	–	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 Exhibits 4.06 and 4.08. (Exhibit 4.41 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

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)

133

INDEX TO EXHIBITS


Exhibit Number	Title
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)

134

INDEX TO EXHIBITS


Exhibit Number	Title
10.04-02	–	Amendment No. 12, dated February 3, 2000, to Exhibit 10.04. (Exhibit 10.04-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

10.05	–	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)

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)

135

INDEX TO EXHIBITS


Exhibit Number	Title
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	–	Reserved

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)

10.15	–	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)

136

INDEX TO EXHIBITS


Exhibit Number	Title
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)

10.21	–	Reserved

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	–	Employment Agreement for Helen Knopp, dated April 30, 1999. (Exhibit 10.46 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999)

137

INDEX TO EXHIBITS


Exhibit Number	Title
†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

138

INDEX TO EXHIBITS


Exhibit Number	Title
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 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)

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)

10.43	–	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)

†††††10.45	–	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)

139

INDEX TO EXHIBITS


Exhibit Number	Title
†††††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)

10.46	–	Employment Agreement between the Company and Ershel C. Redd, Jr. (Exhibit 10.1 to the Company’s Form 8-K, dated May 15, 2007)

10.46-01	–	Separation Agreement between the Company and Ershel C. Redd, Jr. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008)

10.47	–	Separation Agreement between the Company and Gary R. Hedrick. (Exhibit 10.2 to the Company’s Form 8-K, dated as of May 15, 2007)

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.

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 146 of this report)

Exhibit 24 – Power of Attorney:

*24.01	–	Power of Attorney (set forth on page 145 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

140

INDEX TO EXHIBITS


Exhibit Number	Title
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)

*	Filed herewith.

†

Fifteen agreements, substantially identical in all material respects to this exhibit, have been entered into with Gary R. Hedrick; J. Frank Bates; Scott D. Wilson; Steven P. Busser; David G. Carpenter; Robert C. Doyle; Fernando J. Gireud; Hector Gutierrez, Jr.; Helen Knopp; Kerry B. Lore; Hector R. Puente; Andres Ramirez; Gary Sanders; Guillermo Silva, Jr.; and John A. Whitacre; officers of the Company.

††	One agreement, dated as of May 28, 1999, identical in all material respects to this Exhibit, has been entered into with Helen Knopp; officer of the Company.

One agreement, dated as of January 3, 2000, identical in all material respects to this Exhibit, has been entered into with John C. Horne; officer of the Company.

One agreement, dated as of April 23, 2001, identical in all material respects to this Exhibit, has been entered into with Hector Puente; officer of the Company.

One agreement, dated as of November 26, 2001, identical in all material respects to this Exhibit, has been entered into

with J. Frank Bates; officer of the Company.

141

INDEX TO EXHIBITS


Exhibit Number		Title
		Three agreements, dated as of May 10, 2001, identical in all material respects to this Exhibit, have been entered into with Kathryn Hood, Kerry B. Lore and Guillermo Silva, Jr.; officers of the Company.

		Two agreements, dated as of July 15, 2002, identical in all material respects to this Exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.

		Two agreements, dated as of December 4, 2003, identical in all material respects to this Exhibit, have been entered into with Steven P. Busser and Scott D. Wilson; officers of the Company.

†††		In lieu of non-employee director cash compensation, eight agreements, dated as of January 1, 2007, April 1, 2007, July 1, 2007 and October 1, 2007, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.

		In lieu of non-employee director cash compensation, eleven agreements, dated as of May 2, 2007, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.

††††		In lieu of non-employee director cash compensation, eight agreements, dated as of January 1, 2008, April 1, 2008, July 1, 2008 and October 1, 2008, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.

		In lieu of non-employee director cash compensation, ten agreements, dated as of May 8, 2008, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.

		Ten agreements, dated as of May 29, 1998, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; James W. Cicconi; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.

		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 Heitz; director of the Company.

142

INDEX TO EXHIBITS


Exhibit Number		Title
		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 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.

143

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.

144

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, Scott D. Wilson, and Gary D. Sanders, 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.

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 26th day of February 2009.


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
	Chief Executive Officer
/s/ DAVID W. STEVENS	(Principal Executive Officer)	February 26, 2009
(David W. Stevens)
/s/ SCOTT D. WILSON	Executive Vice President, Chief Financial and Chief Administrative Officer (Principal Financial Officer)	February 26, 2009
(Scott D. Wilson)

/s/ DAVID G. CARPENTER	Vice President, Regulatory Services and Controller	February 26, 2009
(David G. Carpenter)

/s/ J. ROBERT BROWN	Director	February 26, 2009
(J. Robert Brown)

/s/ JAMES W. CICCONI	Director	February 26, 2009
(James W. Cicconi)

/s/ GEORGE W. EDWARDS, JR.	Director	February 26, 2009
(George W. Edwards, Jr.)

/s/ JAMES W. HARRIS	Director	February 26, 2009
(James W. Harris)

/s/ GARY R. HEDRICK	Director	February 26, 2009
(Gary R. Hedrick)

/s/ KENNETH R. HEITZ	Director	February 26, 2009
(Kenneth R. Heitz)

/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 26, 2009
(Patricia Z. Holland-Branch)

/s/ MICHAEL K. PARKS	Director	February 26, 2009
(Michael K. Parks)

/s/ ERIC B. SIEGEL	Director	February 26, 2009
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 26, 2009
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 26, 2009
(Charles A. Yamarone)

145