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, 2003

OR

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

For the transition period from                      to                     

Commission file number 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 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 an accelerated filer (as defined in Rule 12b-2 of the Act). YES x NO ¨

As of June 30, 2003, the aggregate market value of the voting stock held by non-affiliates of the registrant was $586,138,226 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of March 5, 2004, there were 47,588,360 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 2004 annual meeting of its shareholders are incorporated by reference into Part III of this report.

DEFINITIONS

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

Abbreviations, Acronyms or Defined Terms	Terms
ANPP Participation Agreement	Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended
APS	Arizona Public Service Company
CFE	Comisión Federal de Electricidad de Mexico, the national electric utility of Mexico
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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Four Corners	Four Corners Generating Station
Freeze Period	Ten-year period beginning August 2, 1995, during which base rates for most Texas retail customers are expected to remain frozen pursuant to the Texas Rate Stipulation
IID	Imperial Irrigation District, an irrigation district in southern California
kV	Kilovolt(s)
kW	Kilowatt(s)
kWh	Kilowatt-hour(s)
Las Cruces	City of Las Cruces, New Mexico
MiraSol	MiraSol Energy Services, Inc., a wholly-owned subsidiary of the Company
MW	Megawatt(s)
MWh	Megawatt-hour(s)
New Mexico Commission	New Mexico Public Regulation Commission
New Mexico Restructuring Act	New Mexico Electric Utility Industry Restructuring Act of 1999
New Mexico Stipulation	Stipulation and Settlement Agreement in Case No. 03-00302-UT between the Company and all other parties to the Company’s rate proceedings before the New Mexico Commission providing for a three-year freeze on base rates after an initial 1% reduction and other matters
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
SFAS	Statement of Financial Accounting Standards
SPS	Southwestern Public Service Company
TEP	Tucson Electric Power Company
Texas Commission	Public Utility Commission of Texas
Texas Fuel Settlement	Settlement Agreement in Texas Docket No. 23530, between the Company, the City of El Paso and various parties whereby the Company increased its fuel factors, implemented a fuel surcharge and revised its Palo Verde Nuclear Generating Station performance standards calculation
Texas Rate Stipulation	Stipulation and Settlement Agreement in Texas Docket No. 12700, between the Company, the City of El Paso, the Texas Office of Public Utility Counsel and most other parties to the Company’s rate proceedings before the Texas Commission providing for a ten-year rate freeze and other matters
Texas Restructuring Law	Texas Public Utility Regulatory Act Chapter 39, Restructuring of the Texas Electric Utility Industry
Texas Settlement Agreement	Settlement Agreement in Texas Docket No. 20450, between the Company, the City of El Paso and various parties providing for a reduction of the Company’s jurisdictional base revenue and other matters
TNP	Texas-New Mexico Power Company

(i)

TABLE OF CONTENTS

Item	Description	Page
	PART I
1	Business	1
2	Properties	19
3	Legal Proceedings	19
4	Submission of Matters to a Vote of Security Holders	21
	PART II
5	Market for Registrant’s Common Equity and Related Stockholder Matters	22
6	Selected Financial Data	23
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
7A	Quantitative and Qualitative Disclosures About Market Risk	35
8	Financial Statements and Supplementary Data	38
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	90
9A	Controls and Procedures	90
	PART III
10	Directors and Executive Officers of the Registrant	90
11	Executive Compensation	90
12	Security Ownership of Certain Beneficial Owners and Management	91
13	Certain Relationships and Related Transactions	91
14	Principal Accounting Fees and Services	91
	PART IV
15	Exhibits, Financial Statement Schedules and Reports on Form 8-K	91

(ii)

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 wholesale customers in Texas and periodically in the Republic of Mexico. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a total capacity of approximately 1,500 MW. For the year ended December 31, 2003, the Company’s energy sources consisted of approximately 50% nuclear fuel, 27% natural gas, 9% coal, 14% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 324,000 residential, commercial, industrial and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 58% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2003). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and periodically sales to the CFE and power marketers. Principal industrial and other large customers of the Company include steel production, copper and oil refining, and United States military installations, including the United States Army Air Defense Center at Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico.

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 March 5, 2004, the Company had approximately 1,000 employees, 31% of whom are covered by a collective bargaining agreement. A new collective bargaining agreement, which expires June 2006, was entered into with these employees in July 2003. The Company has also begun collective bargaining negotiations with an additional 75 employees from the Company’s meter reading and collections area and facilities services area who voted for union representation in 2003.

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.

Facilities

The Company’s net installed generating capacity of approximately 1,500 MW consists of approximately 600 MW from Palo Verde Units 1, 2 and 3, 482 MW from its Newman Power Station, 246 MW from its Rio Grande Power Station, 104 MW from Four Corners Units 4 and 5, 68 MW from its Copper Power Station and 1.32 MW from Hueco Mountain Wind Ranch.

Palo Verde Station

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

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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.

The NRC has granted facility operating licenses and full power operating licenses for Palo Verde Units 1, 2 and 3, which expire in 2024, 2025 and 2027, respectively. In addition, the Company is separately licensed by the NRC to own its proportionate share of 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 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.

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’s decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS.

In accordance with the ANPP Participation Agreement, the Company is required to establish 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. In January 2003, the Company made an additional deposit of $4.7 million into the decommissioning trust fund such that the trust fund met ANPP minimum accumulation levels at December 31, 2002. The Company remained above its minimum funding level as of December 31, 2003. 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.

In August 2002, the Palo Verde Participants approved the 2001 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 1998 study and the 2001 study. The 2001 study estimated that the Company must fund approximately $311.6 million (stated in 2001 dollars) to cover its share of decommissioning costs. The previous cost estimate from the 1998 study estimated that the Company would fund approximately $280.5 million (stated in 1998 dollars). The 2001 estimate reflects an 11.1% increase, or 3.6% average annual compound increase, from the 1998 estimate primarily due to increases in estimated costs for site restoration at each unit, pre and post-shutdown transitioning and decommissioning preparations, spent fuel storage after operations have ceased and the Unit 2 steam generator storage. The decommissioning study is stated in 2001 dollars and makes no inflation assumptions. See “Spent Fuel Storage” below.

Although the 2001 study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not continue to 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. The decommissioning study is updated every three years and a new study is expected to be completed in 2004. See “Disposal of Low-Level Radioactive Waste” below.

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Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under the Texas Restructuring Law, which, among other things, deregulates generation services, the Company, through an affiliated transmission and distribution utility, will be able to collect from customers the costs of decommissioning. The collection mechanism utilized in Texas is a “non-bypassable wires charge” through which all customers, even those who choose to purchase energy from a supplier other than the Company’s retail affiliate, will be required to pay a fee, which includes the cost of nuclear decommissioning, to the Company’s affiliated transmission and distribution utility. In the Company’s case, collection of the fee through the Company’s transmission and distribution utility will begin in Texas if and when retail competition is implemented in the Company’s Texas service territory. See “Regulation – Texas Regulatory Matters – Deregulation” for further discussion.

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 are stored at the new facilities until it is accepted by the DOE for permanent disposal. The 2003 decommissioning study assumes 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 for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

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 until 2010. 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 on-site spent fuel storage costs during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs will be amortized over the burn period of the fuel that will necessitate the use of the alternative on-site storage facilities 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. The Company is unable to predict the outcome of these matters 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. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the

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proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California 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 for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

Steam Generators. Palo Verde has experienced degradation in the steam generator tubes of each unit. The projected service lives of the Palo Verde steam generators are reassessed by APS periodically in conjunction with inspections made during scheduled outages at the Palo Verde units. New steam generators were installed at Unit 2 during 2003 at an estimated total cost to the Company of $47.1 million. This replacement was based on an analysis of the net economic benefit from expected improved performance of the unit and the need to realize continued production from that unit over its full licensed life.

APS has identified accelerated degradation in the steam generator tubes in Units 1 and 3 and has concluded that it is economically desirable to replace the steam generators at those units. While analyses related to timing of installation of steam generators at Units 1 and 3 are ongoing, the Company and the other participants approved the expenditure of $202.1 million (the Company’s portion being $31.9 million) for fabrication and transport of steam generators for Units 1 and 3. In addition, APS has proposed, and the participants have approved the expenditure of $28.4 million (the Company’s portion being $4.5 million) for pre-installation and power uprate work for Units 1 and 3. In addition to these approved amounts, the installation of the Units 1 and 3 replacement steam generators and the completion of power uprates at those units will require the expenditure of $278.6 million (the Company’s portion being $44.0 million). Present plans are for replacement steam generators to be installed at Units 1 and 3 in 2005 and 2007, respectively.

The eventual total cash expenditures for steam generator replacement for Units 1, 2 and 3 is currently estimated to be $718.9 million excluding replacement power costs (the Company’s portion being $113.6 million). As of December 31, 2003, the Company has paid approximately $46.7 million of such costs. The remaining balance is expected to be paid over the course of the steam generator replacements. The Company expects its portion will be funded with internally generated cash.

The Texas Rate Stipulation precludes the Company from seeking a rate increase to recover additional capital costs incurred at Palo Verde during the Freeze Period. The Company cannot assure that its wholesale power rates and its competitive retail rates will be sufficient to recover its costs when or if retail competition for generation services begins. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview.”

Liability and Insurance Matters. In 1957, Congress enacted the Price-Anderson Act as an amendment to the Atomic Energy Act of 1954 to provide a system of financial protection for persons who may be injured or persons who may be liable for a nuclear incident. The Price-Anderson Act expired on December 31, 2003. Existing licensees, such as the Company, are grandfathered and will continue to be subject to the provisions of the Price-Anderson Act in the event Congress does not reauthorize the Price-Anderson Act. The Price-Anderson Amendments Act of 2003 has been placed on the legislative calendar under general order (Calendar No. 422). If passed the Act will amend the Atomic Energy Act to: (i) increase from $63 million to $94 million the maximum amount of standard

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deferred premiums charged a licensee following any nuclear incident under an industry retrospective rating plan; and (ii) increase from $10 million to $15 million (adjusted for inflation) in any one year the maximum amount of such premiums for each facility for which the licensee must maintain the maximum amount of primary financial protection. The amount of DOE indemnification currently available under the act is $9.4 billion. Additionally, the Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under the Price-Anderson Act. The insurance consists of $200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay a retrospective assessment to cover any loss in excess of $200 million. Presently, the maximum retrospective assessment per reactor for each nuclear incident is approximately $88.1 million, subject to an annual limit of $10 million per incident. Based upon the Company’s 15.8% interest in Palo Verde, the Company’s maximum potential retrospective assessment per incident is approximately $41.8 million for all three units with an annual payment limitation of approximately $4.7 million.

The Palo Verde Participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company also has obtained insurance against a portion of any increased cost of generation or purchased power which may result from an accidental outage of any of the three Palo Verde units if the outage exceeds 12 weeks.

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 capacity of approximately 482 MW. The units operate primarily on natural gas but can also operate on fuel oil.

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 capacity of approximately 246 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 generating capacity 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 held on 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.

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Copper Power Station

The Company’s Copper Power Station, located in El Paso, Texas, consists of a 68 MW combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas but can also operate on fuel oil. The Company leased the combustion turbine until December 2003 at which time the facilities were purchased at a total purchase price of $8.4 million, which included the balance of any remaining payments under the lease.

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.

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 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-Diablo Line. The Company wholly 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.

Arroyo-West Mesa Line. The Company wholly owns a 202-mile, 345 kV transmission line from the Arroyo Substation located near Las Cruces, New Mexico, to PNM’s West Mesa Substation located near Albuquerque, 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-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 which interconnects a generator owned and operated by PNM.

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AMRAD-Eddy County Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the AMRAD Substation near Oro Grande, New Mexico, to the Company’s and TNP’s high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico. This terminal enables the Company to connect its transmission system to that of SPS, 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 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 the regulatory agencies. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.

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 $0.9 million as of December 31, 2003, which is related to compliance with federal and state environmental standards. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.

The Company is not aware of any active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the Texas Commission on Environmental Quality, or the New Mexico Environment Department. Furthermore, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as the Superfund law.

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Construction Program

Utility construction expenditures reflected in the following table consist primarily of expanding and updating the transmission and distribution systems and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the fabrication and shipment of Palo Verde Units 1 and 3 steam generators. Replacement power costs expected to be incurred during replacements of Palo Verde steam generators are not included in construction costs. Preliminary studies indicate that the Company will need additional supply-side and demand-side resources in 2006 to meet increasing load requirements on its system. As a result, the Company released a Request for Proposals (“RFP”) seeking bids to supply 150 MW of additional resources beginning in 2006 and an additional 100 MW beginning in 2009. Responses to the Company’s RFP have been received and analyzed. Based on the analysis of the RFPs received to date, it does not appear as if the selection will require the use of cash by the Company to construct a facility to obtain power for its 2006 requirements. The Company is still evaluating its 2009 requirements.

The Company’s estimated cash construction costs for 2004 through 2007 are approximately $277.0 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)
2004	$	74
2005		63
2006		71
2007		69
Total	$	277

By Function (In millions)
Production (1)(2)	$	90
Transmission		19
Distribution		127
General		41
Total	$	277

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

⁽²⁾ Includes $21.8 million for local generation, $9.2 million for the Four Corners Station, $59.8 million for the Palo Verde Station (of which $33.7 million relates to the fabrication and shipment of the steam generators for Units 1 and 3). Excludes $44.0 million for the installation of Palo Verde Units 1 and 3 steam generators, which have yet to be approved by the Palo Verde Participants.

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Energy Sources

General

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

	Years Ended December 31,
Power Source	2003		2002		2001
Nuclear fuel	50	%	52	%	49	%
Natural gas	27		25		32
Coal	9		6		8
Purchased power	14		17		11
Total	100	%	100	%	100	%

Allocated fuel and purchased power costs are generally passed through directly to customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Texas and New Mexico Commissions to determine whether a refund or surcharge based on such historical costs and revenues is necessary. 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, conversion services and enrichment services through 2008. Such contracts could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have a contract for fabrication services through 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 Company has available a total of $100 million under a revolving credit facility that provides for both working capital and up to $70 million for the financing of nuclear fuel. At December 31, 2003, approximately $42.2 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 and has secured this obligation with First Mortgage Collateral Series Bonds. In the Company’s financial statements, the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company.

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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 2003, the Company’s natural gas requirements at the Rio Grande Power Station were met with both short-term and long-term natural gas purchases from various suppliers. Interstate gas is delivered under a firm transportation agreement which expires in 2005 but which is expected to continue beyond 2005. 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 Rio Grande Power Station for the near term. 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 Rio Grande Power Station.

Natural gas for the Newman and Copper Power Stations was primarily supplied pursuant to an intrastate natural gas contract that expires in 2007. The Company will also continue to evaluate short-term natural gas supplies to maintain a reliable and economical supply for the Newman and Copper Power Stations.

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. APS, on behalf of the Company and the other Four Corners Participants, has extended the Four Corners coal contract with the supplier to 2016 to coincide with 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 purchased 103 MW of firm energy in 2003 and will continue to purchase an identical annual amount through 2005 based on a purchase agreement entered into in 2001. This agreement includes demand, energy and transmission charges. Other purchases of shorter duration were made primarily to replace the Company’s generation resources during planned and unplanned outages.

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Operating Statistics
	Years Ended December 31,
	2003			2002			2001
Operating revenues:
Base revenues:
Retail:
Residential	$	171,459		$	166,320		$	159,263
Commercial and industrial, small		165,434			163,553			161,997
Commercial and industrial, large		43,294			43,419			43,644
Sales to public authorities		73,136			70,802			70,372
Total retail base revenues		453,323			444,094			435,276
Wholesale:
Sales for resale		3,223			32,228			52,879
Total base revenues		456,546			476,322			488,155
Fuel revenues		122,761			158,650			164,335
Economy sales		76,536			43,654			92,452
Other		8,519			11,459			24,763
Total operating revenues	$	664,362		$	690,085		$	769,705
Number of customers (end of year):
Residential		289,179			281,874			276,200
Commercial and industrial, small		30,254			29,281			28,573
Commercial and industrial, large		145			141			140
Other		4,524			4,431			4,308
Total		324,102			315,727			309,221
Average annual kWh use per residential customer		6,761			6,694			6,529
Energy supplied, net, kWh (in thousands):
Generated		7,740,923			7,785,938			8,183,713
Purchased and interchanged		1,250,707			1,549,875			951,359
Total		8,991,630			9,335,813			9,135,072
Energy sales, kWh (in thousands):
Retail:
Residential		1,932,171			1,870,931			1,789,199
Commercial and industrial, small		2,096,860			2,076,758			2,069,517
Commercial and industrial, large		1,197,065			1,161,815			1,174,235
Sales to public authorities		1,224,349			1,212,180			1,185,521
Total retail		6,450,445			6,321,684			6,218,472
Wholesale:
Sales for resale		67,754			986,134			1,460,383
Economy sales		1,920,882			1,483,465			929,914
Total wholesale		1,988,636			2,469,599			2,390,297
Total energy sales		8,439,081			8,791,283			8,608,769
Losses and Company use		552,549			544,530			526,303
Total		8,991,630			9,335,813			9,135,072
Native system:
Peak load, kW		1,308,000			1,282,000			1,199,000
Net generating capacity for peak, kW		1,500,000			1,500,000			1,500,000
Total system:
Peak load, kW (1)		1,546,000			1,509,000			1,485,000
Net generating capacity for peak, kW (2)		1,500,000			1,500,000			1,500,000
System capacity factor (3)		60.1	%		61.1	%		60.6	%

⁽¹⁾ Includes spot firm sales of 355,000 kW, 150,000 kW and 60,000 kW for 2003, 2002 and 2001, respectively.

⁽²⁾ Excludes 103,000 kW, 153,000 kW and 163,000 kW of firm on and off-peak purchases for 2003, 2002 and 2001, respectively.

⁽³⁾ System capacity factor includes average firm system purchases of 103,000 kW, 143,000 kW, and 123,000 kW for 2003, 2002 and 2001, respectively.

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Regulation

General

In 1999, both the Texas and New Mexico legislatures enacted electric utility industry restructuring laws requiring competition in certain functions of the industry and ultimately in the Company’s service area. In Texas, the Company is exempt from the requirements of the Texas Restructuring Law, including utility restructuring and retail competition, until the expiration of the Freeze Period in August 2005. In April 2003, the New Mexico Restructuring Act was repealed and as a result, the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas. However, the Company believes that the New Mexico Commission will have to approve the separation of the Company’s operations if and when the Company implements utility restructuring and retail competition for compliance with the Texas Restructuring Law.

Federal Regulatory Matters

Federal Energy Regulatory Commission. The FERC has been conducting an investigation into potential manipulation of electricity prices in the western United States during 2000 and 2001. On August 13, 2002, the FERC initiated a Federal Power Act (“FPA”) investigation into the Company’s wholesale power trading in the western United States during 2000 and 2001 to determine whether the Company engaged in misconduct and, if so, to determine potential remedies. The Company reached settlements with the FERC and other parties in 2002 and 2003. Under the terms of the settlements, the Company agreed to refund a total of $15.5 million of revenues it earned on wholesale power transactions. In July 2003, the FERC approved the settlements and on August 5, 2003, the Company deposited the $15.5 million into an interest bearing escrow account to consummate the settlements. The Company believes the FERC’s order resolved all issues between the FERC and the other parties to this investigation. Under the settlements, the Company has agreed to make wholesale sales pursuant to its cost of service rate authority rather than its market-based rate authority for the period December 1, 2002 through December 31, 2004. This agreement allows the Company to sell power into wholesale markets at its incremental cost plus $21.11 per MWh. To the extent that wholesale market prices exceed these agreed upon amounts, the Company will forego the opportunity to realize these additional revenues. Although this provision has not had a significant impact on the Company’s revenues through December 31, 2003, the Company is unable to predict the effect, if any, this will have on the Company’s 2004 revenues.

RTOs. FERC’s rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”) strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. As a participating transmission owner, the Company will ultimately transfer operational authority of its transmission system to WestConnect subject to receiving any necessary regulatory approvals. On October 10, 2002, FERC issued an order indicating that the Company’s WestConnect proposal satisfied, or with certain modifications would satisfy, the FERC requirements for an RTO under Order 2000. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company, however, is anticipated to be

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no more than a 9% participant in WestConnect and cannot control the terms or timing of its establishment. WestConnect will not be operational before the end of the Freeze Period. The establishment of an RTO in the Company’s service area is an important factor in the Company’s ability to establish a Qualified Power Region as defined in the Texas Restructuring Law and the timing of the operations of WestConnect could affect when and whether the Company’s Texas service territory participates in the Texas deregulated market.

Department of Energy. The DOE regulates the Company’s exports of power to the CFE 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 conduct environmental reviews pursuant to the National Environmental Policy Act.

Texas Regulatory Matters

The rates and services of the Company are regulated in Texas by municipalities and by the Texas Commission. The largest municipality in the Company’s service area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services within municipalities in Texas and original jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.

Deregulation. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation 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. The Texas Restructuring Law, however, specifically recognized and preserved the Company’s Texas Rate Stipulation and Texas Settlement Agreement by, among other things, exempting the Company’s Texas service area from retail competition until the end of the Freeze Period. The Texas Commission recently opened a project (Project No. 28971) to evaluate the readiness of the Company’s service area in Texas for retail competition for generation services. In this project, the Texas Commission may specify in advance the factors that are important in deciding when and whether to open the Company’s service area in Texas to customer choice. One of the key factors that will likely be utilized by the Texas Commission in its determination is the progress that has been made in developing an RTO in the Company’s service area. Public hearings to discuss the readiness of the Company’s service area were held on March 4, 2004 in El Paso and will be held in Austin in April 2004. 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

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deregulation will not adversely affect the future operations, cash flows and financial condition of the Company.

Fuel. Although the Company’s base rates are frozen in Texas, pursuant to Texas Commission rules and the Texas Rate Stipulation, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with providing electricity and seek recovery of past undercollections of fuel revenues, subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.

On March 10, 2004, the Texas Commission announced its decision in PUC Docket No. 26194, a case in which the Company sought to reconcile its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge because of fuel undercollections from January 1999 through December 2001. The Texas Commission disallowed approximately $4.5 million of Texas jurisdictional expenses, before interest, consisting primarily of (i) approximately $4.2 million of purchased power expenses which the Texas Commission characterized as “imputed capacity charges,” and (ii) approximately $0.3 million in fees which were deemed to be administrative costs, not recoverable as fuel. In Texas, capacity charges are not eligible for recovery as fuel expenses, but are to be recovered through the Company’s base rates. As the Company’s base rates were frozen during the time period in question, the $4.2 million of “imputed capacity charges” would be permanently disallowed, and hence not recoverable from its Texas customers.

The Texas Commission’s decision modifies the Proposal for Decision issued September 19, 2003 by the Administrative Law Judges (“ALJs”). The ALJs had recommended that approximately $21.2 million of the Company’s purchased power expense should be disallowed as imputed capacity charges and not recovered from Texas jurisdictional customers.

The Company has incurred similar purchased power costs for the fuel reconciliation period beginning January 1, 2002. The Company believes that it has accounted for its purchased power costs during the reconciliation period beginning January 2002 in a manner consistent with the Texas Commission’s decision in PUC Docket No. 26194. However, the Texas Commission has indicated its desire to conduct a generic rulemaking proceeding to determine a statewide policy for the appropriate pricing of capacity in purchased power contracts. There can be no assurance, however, as to the outcome of such rulemaking and the potential impact on the Company with respect to fuel recovery in future reconciliation periods if the Texas Commission adopts a different methodology in a subsequent rulemaking proceeding.

The Texas Commission’s decision is subject to appeal by the various parties and the Company is unable to predict the ultimate outcome of any appeals that may be filed in this case.

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 24-month period, should fall below 35%, the Texas Commission can also reconsider the rate treatment

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of Palo Verde, regardless of the provisions of the Texas Rate Stipulation and the Texas Settlement Agreement. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. Under the performance standards as modified by the Texas Fuel Settlement, the Company has calculated the performance awards for the reporting periods ending in 2003, 2002 and 2001 to be approximately $0.8 million, $1.3 million and $1.1 million, respectively. These rewards will be included, along with energy costs incurred and revenues billed, as part of the Texas Commission’s review during a future periodic fuel reconciliation proceeding 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 are recorded when assessed as probable by the Company.

Texas Renewable Energy Requirement. Chapter 39 of the Public Utility Regulatory Act (“PURA”), implemented by Senate Bill 7 in the 1999 legislative session, requires that, by January 1, 2009, an additional 2,000 MW of generating capacity from renewable energy technologies be installed in the state. The renewable energy requirement is to be added in increments with the cumulative installed renewable capacity in Texas totaling 1,703 MW by January 1, 2005, 2,280 MW by January 1, 2007, and 2,880 MW by January 1, 2009. The requirements of this goal are placed on retail electric providers (“REPs”), who provide competitive retail electric service in the state of Texas. Utilities that have not implemented retail competition may have renewable energy requirements based on orders of the Texas Commission.

Until the end of the Freeze Period, the Company is exempt from PURA Chapter 39 and Texas Commission rules implementing the renewable requirements. However, once the Freeze Period ends, any renewable energy requirement applicable to the Company could be based on the percentage of the competitive retail load that will be served by the Company (or the Company’s REP) in relation to the total competitive retail load served in Texas. It is not clear when the Company will need to meet a renewable energy requirement in Texas or what the obligation will be. The Company is currently reviewing the outcome of its New Mexico RFPs, for renewable energy to assess possible scenarios for meeting possible future Texas requirements, which includes the purchase of renewable power and/or credits.

New Mexico Regulatory Matters

The New Mexico Commission has jurisdiction over the Company’s rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Mexico Commission’s decisions are subject to judicial review. The largest city in the Company’s New Mexico service territory is Las Cruces.

Deregulation. In April 2003, the New Mexico Restructuring Act was repealed and as a result the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas.

Fuel. In June 2001, the New Mexico Commission approved a fuel and purchased power cost adjustment clause. On May 31, 2003, the Company submitted a rate compliance filing whereby the Company proposed to continue a base rate recovery of $0.01949 per kWh and continue the fuel and

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purchased power cost adjustment to recover the remainder of fuel and purchased power costs. The Company and all intervenors entered into the New Mexico Stipulation on the Company’s compliance filing.

New Mexico Rate Stipulation. On January 21, 2004, the Company and all intervenors to the rate compliance filing entered into and filed the New Mexico Stipulation whereby, among other things, the Company agreed for a period of three years beginning June 1, 2004 to (i) freeze base rates after an initial non-fuel base rate reduction of 1%; (ii) fix fuel and purchased power cost associated with 10% of the Company’s jurisdictional retail sales in New Mexico at $0.021 per kWh; (iii) leave subject to reconciliation the remaining 90% of the Company’s New Mexico jurisdictional fuel and purchased power costs; (iv) continue the collection of a portion of fuel and purchased power costs in base rates as presently collected in the amount of $0.01949 per kWh; (v) price power provided from Palo Verde Unit 3 to the extent of its availability at an 80% nuclear, 20% gas fuel mix (currently such power is priced at 75% nuclear, 25% gas fuel mix) and (vi) deem reconciled, for the period June 15, 2001 through May 31, 2004, the Company’s fuel and purchased power costs for the New Mexico jurisdiction. The New Mexico Stipulation is subject to the New Mexico Commission’s approval. The New Mexico Commission hearing on the New Mexico Stipulation was held on February 25, 2004. The Company anticipates a ruling on the New Mexico Stipulation prior to June 2004 with the new rates implemented on or about June 1, 2004. The Company cannot predict the outcome of these proceedings or how the New Mexico Commission will rule.

New Mexico Renewable Energy Requirement. The New Mexico Commission has adopted renewable energy portfolio requirements and has mandated that 5% of all New Mexico retail jurisdictional energy sales in 2006 be supplied by renewable resources or certificates. The renewable portfolio standard increases by 1% each year until 2011, and is set at 10% in 2011 and thereafter. In February 2004, the Company issued a RFP for renewable energy from certified renewable sources to meet the renewable energy portfolio requirements. Based on responses to the RFP, the Company will develop a plan to meet the New Mexico Commission’s renewable energy requirements. In the 2004 New Mexico legislative session, the Renewable Energy Act was enacted which directs the New Mexico Commission to adopt a rule consistent with the law, and requires rate recovery for the reasonable costs of compliance with the renewable requirements.

Sales for Resale

The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. No such notice has been received. The Company also made sales of interruptible energy to CFE during the months of June and July 2003 of 13,711 MWh and 4,525 MWh, respectively.

Power Sales Contracts

As of March 5, 2004, the Company had entered into one significant agreement with a counterparty for forward off-peak firm sales of electricity of 50 MW for 2004.

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The Company also has an agreement with a counterparty for power exchanges under which the Company received 30 MW of on-peak capacity and associated energy during 2003 at the Eddy County tie and concurrently delivered the same amount at Palo Verde and/or Four Corners. The on-peak exchange amount remains at 30 MW through 2005. The agreement also gives the counterparty the option to deliver up to 133 MW of off-peak capacity and associated energy to the Company at the Eddy County tie through 2005 in exchange for the same amount of energy concurrently delivered by the Company at Palo Verde and/or Four Corners. The Company will receive a guaranteed margin on any energy exchanged under the off-peak agreement. See “Purchased Power.”

Franchises and Significant Customers

City of El Paso Franchise

The Company’s major franchise is with the City of El Paso, Texas (“City”). The franchise agreement includes a 2% annual franchise fee (approximately $7.7 million per year currently) and provides an arrangement for the Company’s utilization of public rights-of-way necessary to serve its retail customers within the City. The franchise with the City extends through August 1, 2005.

In a provision of the franchise agreement, the City has an option to acquire all of the non-cash assets of the Company at the end of the term of the franchise on August 1, 2005, at a purchase price equal to the fair market value of the assets (measured on a cost of reproduction basis) on the date one year prior to the end of the term. The purchase price is then subject to certain adjustments to roll the value of the assets forward to the end of the term. If the City wishes to exercise its option, it must deliver written notice to the Company one year prior to the expiration of the franchise term.

Las Cruces Franchise

In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.1 million per year currently) for the provision of electric distribution service. Las Cruces is prohibited during this seven-year period from taking any action to condemn or otherwise attempt to acquire the Company’s distribution system, or attempt to operate or build its own electric distribution system. Las Cruces will have a 90-day non-assignable option at the end of the Company’s seven-year franchise agreement to purchase the portion of the Company’s distribution system that serves Las Cruces at a purchase price of 130% of the Company’s book value at that time. If Las Cruces exercises this option, it is prohibited from reselling the distribution assets for two years. If Las Cruces fails to exercise this option, the franchise and standstill agreements will be extended for an additional two years.

Military Installations

The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company currently has long-term contracts with all three military bases that it serves. The Company signed a contract with Ft. Bliss in December 1998 under which Ft. Bliss will take service from the Company through December 2008. The Company has a contract to provide retail electric service to Holloman for a ten-year term which began in December 1995. In May 1999, the Army and the Company entered into a new ten-year contract to provide retail electric service to White Sands.

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Executive Officers of the Registrant The executive officers of the Company as of March 5, 2004, were as follows:
Name	Age	Current Position and Business Experience
Gary R. Hedrick	49	Chief Executive Officer, President and Director since November 2001; Executive Vice President, Chief Financial and Administrative Officer from August 2000 to November 2001; Vice President, Chief Financial Officer and Treasurer from August 1996 to August 2000.
Terry Bassham	43	Executive Vice President, Chief Financial and Administrative Officer since November 2001; Executive Vice President and General Counsel from August 2000 to November 2001; Vice President and General Counsel from January 1999 to August 2000; General Counsel from August 1996 to January 1999.
J. Frank Bates	53	Executive Vice President and Chief Operations Officer since November 2001; Vice President – Transmission and Distribution from August 1996 to November 2001.
Raul A. Carrillo, Jr.	42	Senior Vice President, General Counsel and Corporate Secretary since February 2003; Senior Vice President and General Counsel from July 2002 to February 2003; General Counsel from January 2002 to July 2002; Associate and Shareholder with Sandenaw, Carrillo & Piazza, P.C. from March 1996 to January 2002.
Steven P. Busser	35	Treasurer since February 2003; Assistant Chief Financial Officer from June 2002 to February 2003; Vice President – International Controller for Affiliated Computer Services, Inc. from August 2001 to June 2002; Vice President – International Controller for National Processing Company, Inc. from June 2000 to August 2001; Assurance Manager with KPMG, LLP from June 1998 to June 2000.
Fernando J. Gireud	46	Vice President – Power Marketing and International Business since February 2003; Vice President – International Business from July 2002 to February 2003; Director – International Business Affairs from February 2002 to July 2002; Director – International Business Affairs – MiraSol from November 1999 to February 2002; Manager of Environmental Affairs from April 1994 to November 1999.
Helen Knopp	61	Vice President – Customer and Public Affairs since April 1999; Executive Director of the Rio Grande Girl Scout Council from September 1991 to April 1999.
Kerry B. Lore	44	Vice President – Administration since May 2003; Controller from October 2000 to May 2003; Assistant Controller from April 1999 to October 2000; Manager of Accounting Services from July 1993 to April 1999.
Robert C. McNiel	57	Vice President – New Mexico Affairs since December 1997.
Hector R. Puente	47	Vice President – Power Generation since April 2001; Manager – Substations and Relaying from August 1996 to April 2001.
Guillermo Silva, Jr.	50	Vice President – Information Services since February 2003; Secretary from January 1994 to February 2003.
John A. Whitacre	54	Vice President – Transmission and Distribution since July 2002; Assistant Vice President – System Operations from August 1989 to July 2002.
Scott D. Wilson	50	Controller since September 2003; Owner of Wilson Consulting Group from June 1992 to September 2003.

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

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Item 2. Properties

The principal properties of the Company are described in Item 1, “Business,” and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, easements, or on streets or highways by public consent. Substantially all of the Company’s utility plant is subject to liens to secure the First Mortgage Bonds.

In addition, the Company leases executive and administrative offices in El Paso, Texas under a lease which expires in May 2007.

Item 3. Legal Proceedings

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

On January 16, 2003, the Company was served with a complaint on behalf of a purported class of shareholders alleging violations of the federal securities laws (Roth v. El Paso Electric Company, et al., No. EP-03-CA-0004). The complaint was filed in the El Paso Division of the United States District Court for the Western District of Texas. The suit seeks undisclosed compensatory damages for the class as well as costs and attorneys’ fees. The lead plaintiff, Carpenters Pension Fund of Illinois, filed a consolidated amended complaint on July 2, 2003, alleging, among other things, that the Company and certain of its current and former directors and officers violated securities laws by failing to disclose that some of the Company’s revenues and income were derived from an allegedly unlawful relationship with Enron. The allegations arise out of the FERC investigation of the power markets in the western United States during 2000 and 2001, which the Company previously settled with the FERC Trial Staff and certain intervening parties. See Part I, Item 1, “Regulation – Federal Regulatory Matters.” On August 15, 2003, the Company and the individual defendants filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. On November 26, 2003, the Court denied the motion to dismiss as to the Company and three of the individual defendants and granted the motion to dismiss as to two individual defendants. The lead plaintiff filed its motion for class certification on January 9, 2004, seeking to certify a class consisting of all persons who purchased or otherwise acquired Company securities between February 14, 2000 and October 21, 2002. This matter is presently set for trial on March 28, 2005. While the Company believes the lawsuit is without merit and intends to defend itself vigorously, the Company is unable to predict the outcome.

On February 10, 2003, the Company received a letter written by a Pennsylvania law firm on behalf of the holder of approximately 200 shares of common stock of the Company (the “shareholder”), that demands that the Company commence a lawsuit against each member of the Board of Directors to recover damages allegedly sustained by the Company as a result of alleged breaches of fiduciary duties by the Board. The shareholder contends that, from 1997 to 2002, the Board knowingly caused or allowed the Company to participate in improper transactions with Enron Corporation and certain of its

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subsidiaries. The allegations appear to duplicate factual questions first raised by the FERC in an investigation of the power markets in the western United States during 2000 and 2001. As noted above, the Company reached a settlement of the FERC investigation with the FERC Trial Staff and certain intervenors. In accordance with Texas law, the independent and disinterested directors of the Company conducted an independent inquiry and concluded that a lawsuit against the Board is not in the best interests of the Company. To date, the shareholder has not filed a shareholder derivative lawsuit against the members of the Board. The Company is unable to predict the outcome of this matter.

On May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state anti-trust laws, as well as for breach of contract and fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. On December 4, 2003, the case was transferred to the United States District Court for the Southern District of California for inclusion in the California Wholesale Electricity Antitrust Multi-District Litigation cases pending in that district (re-styled Port of Seattle v. Avista Corporation, et al., No. CV 03-2474-RHW, MDL No. 1403). The Company, together with several other defendants, filed a motion to dismiss on July 29, 2003. The motions to dismiss are scheduled for oral argument on March 26, 2004. While the Company believes the lawsuit is without merit and will defend itself vigorously, it is unable to predict the outcome of this case.

The IRS has disputed whether the Company was entitled to deduct certain payments made in 1996 related to Palo Verde and its treatment of a litigation settlement in 1997 related to a terminated merger agreement. The Company has reached a tentative agreement, subject to IRS final approval, to settle these and all other issues relative to its 1996 through 1998 federal income tax returns. The Company expects the IRS will make a final decision regarding the proposed settlement by mid 2004. Should the proposed settlement be rejected by the IRS, the Company cannot predict the eventual outcome of this matter. However, the Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome cannot be predicted with certainty, and while the contingent tax reserve may not in fact be sufficient, the Company believes that the amount at December 31, 2003 is a reasonable estimate of any additional tax that may be due.

On February 9, 2004, Enron North America Corp. (“ENA”) filed suit against the Company seeking payment of approximately $5.4 million, plus interest and costs, relating to certain natural gas supply contracts (Enron North America Corp. v. El Paso Electric Co., Case No. 01-16034, United States Bankruptcy Court, Southern District of New York). The complaint alleges that ENA entered into two natural gas supply contracts with the Company which automatically terminated as a result of ENA’s bankruptcy. ENA contends that, under the terms of the contracts, the Company owes ENA termination payments because the market price of natural gas at the date of termination was lower than the contract price. While ENA acknowledges that the contracts contain a provision (the “One-Way Payment Provision”) under which the termination payment would be calculated to be zero, ENA seeks a ruling

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from the court that the One-Way Payment Provision is unenforceable and that the Company should be required to pay termination payments in the amount of approximately $5.4 million, plus interest and costs. The first of these two contracts covers gas to be supplied by ENA during the months of November and December of 2001 (the “2001 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2001 Contract is approximately $1.8 million. The second of these two contracts covers gas to be supplied by ENA during the months of January through December of 2002 (the “2002 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2002 Contract is approximately $3.6 million. Based upon the Company’s assessment of the probability of an adverse outcome, the Company has expensed a pre-tax amount of $1.5 million as of December 31, 2003 for this matter. The Company intends to defend itself vigorously, but cannot predict the outcome of this matter.

On October 2 and 3, 2003, employees in the Company’s meter reading and collections areas, comprised of 68 employees, voted in favor of representation by the International Brotherhood of Electrical Workers, Local 960 (“Local 960”). This vote was certified by the National Labor Relations Board (“NLRB”) on October 14, 2003. In addition, employees in the Company’s facilities services area, comprised of seven employees, voted in favor of representation by Local 960 on October 16, 2003. This vote was certified by the NLRB on October 24, 2003. The Company has begun collective bargaining negotiations with Local 960 on behalf of these employees.

On November 3, 2003, TNP filed a complaint against the Company with the FERC, asking the FERC to make a determination that TNP has a rollover right to network-type transmission service over the Company’s transmission system. TNP asserts that it has such rights under the rollover provisions of FERC Order No. 888 relating to its power sale agreement with the Company that expired on December 31, 2002. The Company’s position is that the transmission service provided by the Company to TNP under the expired power sale agreement was point-to-point service and not network service and that the Company does not have the capacity to provide the network service that TNP seeks. Due to existing transmission constraints, a FERC ruling granting TNP’s request could adversely impact the Company’s ability to import lower cost power from Palo Verde and Four Corners to serve its base load to the extent of the transmission rights granted to TNP. A hearing on this matter before an administrative law judge is scheduled for June 15, 2004. The Company cannot predict the likely outcome of this matter or the full effect that an adverse ruling would have on the Company.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

The Company’s common stock began trading on the New York Stock Exchange on December 4, 2002, under the symbol “EE.” Prior to that date, the Company’s common stock traded on the American Stock Exchange. The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the New York Stock Exchange and the American Stock Exchange for the periods indicated below were as follows:

	Sales Price
	High		Low		Close
					(End of period)
2002
First Quarter	$	16.05	$	13.25	$	15.65
Second Quarter		16.20		12.20		13.85
Third Quarter		14.16		10.90		11.88
Fourth Quarter		12.60		9.25		11.00
2003
First Quarter	$	11.99	$	10.10	$	10.80
Second Quarter		12.50		10.76		12.33
Third Quarter		12.55		10.90		11.55
Fourth Quarter		13.63		11.55		13.35

As of March 5, 2004, there were 4,646 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 deleveraging and stock repurchase programs with the goal of improving its capital structure, bond ratings, and earnings per share.

During 2003, the Company repurchased 2.1 million shares of common stock for $24.2 million to complete its previously approved stock repurchase programs. Since the inception of the stock repurchase programs in 1996, the Company repurchased 15 million shares in total at an aggregate cost of $171.0 million, including commissions. In February 2004, the Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock. The Company may make purchases of its stock 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 option plans, or may be retired.

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Item 6. Selected Financial Data

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

	Years Ended December 31,
	2003		2002		2001		2000		1999
Operating revenues	$	664,362	$	690,085	$	769,705	$	701,649	$	570,469
Operating income		80,215		110,607		167,602		168,974		157,336
Income before cumulative effect of accounting change		20,616		28,967		63,659		58,392		40,473
Cumulative effect of accounting change, net of income tax expense		39,635		—		—		—		—
Net income applicable to common stock		60,251		28,967		63,659		58,392		28,276
Basic earnings per common share:
Income before cumulative effect of accounting change		0.42		0.58		1.25		1.08		0.48
Cumulative effect of accounting change, net of income tax expense		0.82		—		—		—		—
Net income		1.24		0.58		1.25		1.08		0.48
Weighted average number of common shares outstanding		48,424,212		49,862,417		50,821,140		54,183,915		59,349,468
Diluted earnings per common share:
Income before cumulative effect of accounting change		0.42		0.57		1.23		1.06		0.47
Cumulative effect of accounting change, net of income tax expense		0.81		—		—		—		—
Net income		1.23		0.57		1.23		1.06		0.47
Weighted average number of common shares and dilutive potential common shares outstanding		48,814,761		50,380,468		51,722,351		55,001,625		59,731,649
Cash additions to utility property, plant and equipment		77,080		65,065		70,739		64,612		51,826
Total assets		1,595,854		1,646,989		1,644,439		1,660,105		1,664,436
Long-term debt and financing and capital lease obligations		608,722		614,375		619,365		740,223		811,607
Common stock equity		499,822		456,642		450,193		412,034		421,258

The selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplementary Data.”

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

Statements in this document, other than statements of historical information, are forward-looking statements that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company’s filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: (i) increased prices for fuel and purchased power and determinations by regulators that may adversely affect the Company’s ability to recover incurred fuel costs in rates; (ii) fluctuations in wholesale margins due to uncertainty in the wholesale power market; (iii) unanticipated increased costs associated with scheduled and unscheduled outages; (iv) the cost of replacing steam generators for Palo Verde Units 1 and 3 and other costs at Palo Verde; (v) the costs of legal defense and possible judgments which may accrue as the result of litigation arising out of the FERC investigation or any other regulatory proceeding; (vi) deregulation of the electric utility industry; and (vii) other factors discussed below under the headings “Summary of Critical Accounting Policies and Estimates,” “Overview” and “Liquidity and Capital Resources.” The Company’s filings are available from the Securities and Exchange Commission or may be obtained through the Company’s website, www.epelectric.com. Any such forward-looking statement is qualified by reference to these risks and factors. The Company cautions that these risks and factors are not exclusive. The Company does not undertake to update any forward-looking statement that may be made from time to time by or on behalf of the Company except as required by law.

Summary of Critical Accounting Policies and Estimates

Note A to the Consolidated Financial Statements contains a summary of the significant accounting policies utilized by the Company. The preparation of these 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 estimates, which are both important to the portrayal of the Company’s financial condition and results of operations and which require complex, subjective judgments, include the following:

• Collection of fuel expense

• Value of net utility plant in service

• Decommissioning costs

• Future pension and other postretirement obligations

• Reserves for tax dispute

Collection of Fuel Expense

In general, through regulation, the Company’s fuel and purchased power expenses are passed through to its regulated customers. These costs are subject to reconciliation by the Texas and New Mexico Commissions. Prior to the completion of a reconciliation, the Company records fuel expenses as incurred. In the event that a disallowance occurs during a reconciliation proceeding, the

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amounts recorded for fuel and purchased power expenses could differ from the amounts allowed to be collected by the Company from its customers and the Company could incur a loss to the extent of the disallowance.

Value of Net Utility Plant in Service

In 1996, when it emerged from bankruptcy, the Company recast its financial statements by applying fresh-start reporting in accordance with Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.” In this process, the Company attributed value to its integrated utility system, including its generation assets, after it had established the value of its pro forma capital structure based on management’s estimates of future operating results. The Company valued its generation assets such that the depreciated value of its generation assets would be approximately equal to their estimated fair value at the end of the Freeze Period. This is important because at the beginning of retail competition in Texas, the Company will no longer be permitted to recover in rates any “stranded costs”, that is, the difference between the book value and the market value of its electric generation assets. If at any time the Company determines that estimated, undiscounted future net cash flows from the operations of the generation assets are not sufficient to recover their net book value, then it will be required to write down the value of these assets to their fair values. Any such writedown would be charged to earnings. The Company currently believes that its rates are sufficient to collect before 2005 substantially all costs that would otherwise be “stranded” under relevant laws in Texas and that future net cash flows after 2005 from the generating assets will be sufficient to recover their net book values.

Decommissioning Costs

Pursuant to the ANPP Participant Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2, and 3 and associated common areas. The Company and other Palo Verde Participants rely upon decommissioning cost studies and make interest 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. The Company determines how it will fund its share of those estimated costs by making assumptions about future investment returns and future cost escalations. The funds are invested in professionally managed investment trust accounts. The Company is required to establish a minimum accumulation and a minimum funding level in its decommissioning trust accounts at the end of each annual reporting period in accordance with the ANPP Participation Agreement. If actual decommissioning costs exceed estimates, the Company would incur additional expenses related to decommissioning. Further, if the rates of return earned by the trusts fail to meet expectations, the Company will be required to increase its funding to the decommissioning trust accounts. Although the Company cannot predict the results of future studies, the Company believes that the liability it has recorded for its decommissioning costs will be adequate to provide for the Company’s 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. The Company believes that its current annual funding levels of the decommissioning trust will adequately provide for the cash requirements associated with decommissioning. Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear

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decommissioning. Under deregulation legislation in Texas, the Company expects to continue to be able to collect from customers the costs of decommissioning.

Future Pension and Other Postretirement Obligations

In accounting for its retirement plans and other postretirement benefits, the Company makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. The accounting for retirement plans and other postretirement obligations allows for a smoothed recognition of changes in benefit obligations and plan performance over the service lives of the employees who benefit under the plans. The primary assumptions are discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the period, or on the amount of related liabilities reflected on the Company’s consolidated balance sheet.

Reserves for Tax Dispute

The IRS has disputed whether the Company was entitled to deduct certain payments made in 1996 related to Palo Verde and its treatment of a litigation settlement in 1997 related to a terminated merger agreement. The Company has reached a tentative agreement, subject to IRS final approval, to settle these and all other issues relative to its 1996 through 1998 federal income tax returns. The Company expects the IRS will make a final decision regarding the proposed settlement by mid 2004. Should the proposed settlement be rejected by the IRS, the Company cannot predict the eventual outcome of this matter. However, the Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome cannot be predicted with certainty, and while the contingent tax reserve may not in fact be sufficient, the Company believes that the amount at December 31, 2003 is a reasonable estimate of any additional tax that may be due.

Overview

El Paso Electric Company is an investor owned electric utility that serves retail customers in west Texas and southern New Mexico and wholesale customers in Texas and periodically in the Republic of Mexico. The Company owns or has substantial ownership interests in six electrical generating facilities providing it with a total capacity of approximately 1,500 MW. The Company’s energy sources consist of nuclear fuel, natural gas, coal, wind powered resources and purchased power. The Company owns or has significant ownership interests in four major 345 kV transmission lines and three 500 kV transmission lines utilized to transfer power from Palo Verde and Four Corners, and owns the transmission and distribution network within its retail service territory. The Company is subject to regulation by the Texas and New Mexico Commissions and, with respect to wholesale power sales, transmission of electric power and the issuance of securities, by the FERC.

The Company faces a number of risks and challenges that could negatively impact its operations and financial results. The most significant of these risks and challenges are the deregulation of the electric utility industry, the possibility of increased costs especially from Palo Verde and the Company’s debt service obligations.

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The electric utility industry in general and the Company in particular are facing significant challenges and increased competition as a result of changes in federal provisions relating to third-party transmission services and independent power production, as well as changes in state laws and regulatory provisions relating to wholesale and retail service. In 1999, both Texas and New Mexico passed industry deregulation legislation requiring the Company to separate its transmission and distribution functions, which would remain regulated, from its power generation and energy services businesses, which would operate in a competitive market in the future. New Mexico repealed the New Mexico Restructuring Act in April 2003, and the Company’s operations in New Mexico will remain fully regulated. In Texas, the Company’s service territory has not yet been deregulated, but the Company is preparing for retail competition. If the Company does not enter retail competition for generating services at the end of the Freeze Period, the Company’s generating services will continue to be regulated by the Texas Commission. 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 will not adversely affect the future operations, cash flows and financial condition of the Company.

The changing regulatory environment and the potential for unregulated power production have created a substantial risk that the Company will lose important customers. The Company’s wholesale and large retail customers already have, in varying degrees, alternate sources of economical power, including co-generation of electric power. In fact, the Company has lost certain large retail customers to self-generation and/or co-generation and has seen reductions in wholesale sales due to new sources of generation. If the Company loses a significant portion of its retail customer base, the Company may not be able to replace such revenues through either the addition of new customers, an increase in rates to remaining customers, or sales in the economy market.

Another risk to the Company is potential increased costs, including the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses; (ii) the replacement of steam generators in Palo Verde Units 1 and 3; (iii) an extended outage of any of the Palo Verde units; (iv) increases in estimates of decommissioning costs; (v) the storage of radioactive waste, including spent nuclear fuel; (vi) insolvency of other Palo Verde Participants; and (vii) compliance with the various requirements and regulations governing commercial nuclear generating stations. At the same time, the Company’s retail base rates in Texas are effectively capped through a rate freeze ending in August 2005. As a result, the Company cannot raise its base rates in Texas in the event of increases in non-fuel costs or loss of revenue. Additionally, upon initiation of competition, there may be competitive pressure on the Company’s power generation rates which could reduce its profitability. The Company cannot assure that its 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.

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Liquidity and Capital Resources

The Company’s principal liquidity requirements in the near-term are expected to consist of interest payments on the Company’s indebtedness, operating and capital expenditures related to the Company’s generating facilities and transmission and distribution systems, income and other taxes, and reorganization costs related to deregulation in Texas, if and when deregulation occurs. The Company expects that cash flows from operations will be sufficient for such purposes.

The Company’s contractual obligations as of December 31, 2003 are as follows (in thousands):

	Payments due by period
	Total		2004		2005 and 2006			2007 and 2008		2009 and Later
Long-Term Debt:
First mortgage bonds	$	395,366	$	—	$	186,182	(1)	$	—	$	209,184	(2)
Pollution control bonds		193,135		—		193,135	(3)		—		—
Promissory note		151		116		35			—		—
Financing Obligations:
Nuclear fuel		42,176		21,990		20,186			—		—
Purchase Obligations:
Capacity power contract		16,818		8,409		8,409			—		—
Fuel contracts:
Coal		88,350		7,068		14,136			14,136		53,010
Gas (4)		80,040		20,010		40,020			20,010		—
Nuclear fuel (5)		16,652		12,427		4,225			—		—
Operating lease (6)		3,400		1,000		2,000			400		—
Total	$	836,088	$	71,020	$	468,328		$	34,546	$	262,194

⁽¹⁾ In early 2004, the Company repurchased $4.0 million of its first mortgage bonds which were scheduled to mature in 2006.

⁽²⁾ In early 2004, the Company repurchased $2.0 million of its first mortgage bonds which become callable in 2006.

⁽³⁾ The pollution control bonds are scheduled for remarketing in 2005.

⁽⁴⁾ This amount is based on the minimum volumes per the contract at the current market price at the end of the year.

⁽⁵⁾ Some of the nuclear fuel contracts are based on a fixed price adjusted for an index. The index used is the current index at the end of the year.

⁽⁶⁾ The Company has one significant operating lease for administrative offices which expires in May 2007.

Pollution control bonds of $193.1 million are subject to remarketing in 2005, and first mortgage bonds of $182.2 million are scheduled to mature in 2006. The Company expects that these obligations and the $100 million revolving credit facility, which matures in January 2005 (against which approximately $42.2 million had been drawn for nuclear fuel purchases as of December 31, 2003) will be refinanced through the capital and credit markets. Additionally, the Company has $207.2 million of first mortgage bonds which become callable in 2006. The Company’s ability to access capital and credit markets may be adversely affected by uncertainties related to operating in a competitive energy market, tight credit markets and debt rating agency actions.

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Long-term capital requirements of the Company will consist primarily of construction of electric utility plant and the payment of interest on and retirement and refinancing of debt. Utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, possible addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement steam generators in Palo Verde Units 1 and 3. See Part I, Item 1, “Business – Construction Program.”

During 2003, 2002 and 2001, the Company generated $0.7 million and utilized $96.6 million and $128.0 million, respectively, of regular federal tax loss carryforwards. The Company anticipates that existing regular federal tax loss carryforwards will be fully utilized by mid-2004, should the IRS settlement for the tax years 1996 through 1998 be approved by the IRS, and that the Company’s cash flow requirements for income taxes in 2004 will increase compared to the requirement for 2003.

The Company anticipates its cash flow requirements associated with its retirement plans and other postretirement benefit plans and its cash flow requirements related to contributions to the decommissioning trust funds will decrease as compared to the related cash flow requirements in 2003. The Company contributed an additional $4.7 million to the decommissioning trust funds in January 2003 and an additional $3.2 million to one of its retirement plans in September 2003 in order to meet its funding requirements as of December 31, 2002. The Company is continually evaluating its funding requirements related to its retirement plans, other postretirement benefit plans, and decommissioning trust funds.

As of December 31, 2003, the Company had approximately $34.4 million in cash and cash equivalents, a decrease of $40.7 million from the balance of $75.1 million on December 31, 2002. This decrease was primarily the result of the retirement in February 2003 of the Company’s Series C First Mortgage Bonds. Any amounts not borrowed under the Company’s $100 million revolving credit facility for nuclear fuel purchases may be used by the Company for working capital needs. As of December 31, 2003, approximately $42.2 million had been drawn for nuclear fuel purchases. No amounts are currently outstanding on this facility for working capital needs.

The Company has significant debt service obligations. Since inception of its deleveraging program in 1996, the Company has repurchased or retired with internally generated cash $556.5 million of first mortgage bonds, including the repayment of approximately $36.1 million of Series C First Mortgage Bonds at their maturity and the repurchase of approximately $3.3 million of first mortgage bonds during the first quarter of 2003. First Mortgage Bonds totaling $6.0 million were repurchased in early 2004. Common stock equity as a percentage of capitalization, including current portion of long-term debt and financing obligations, was 44% as of December 31, 2003.

The degree to which the Company is leveraged could have important consequences for the Company’s liquidity, including (i) limiting the Company’s ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes in the future, and (ii) placing the Company at a competitive disadvantage by limiting its financial flexibility to respond to the demands of the competitive market and making it more vulnerable to adverse economic or business changes.

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During 2003, the Company repurchased 2.1 million shares of common stock for $24.2 million to complete its previously approved stock repurchase programs. Since the inception of the stock repurchase programs in 1996, the Company repurchased 15 million shares in total at an aggregate cost of $171.0 million, including commissions. In February 2004, the Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock. The Company may make purchases of its stock 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 option plans, or may be retired.

Historical Results of Operations

	Years ended December 31,
	2003		2002				2001
	Actual		Actual		Pro forma		Actual		Pro forma
Income before cumulative effect of accounting change (in thousands)	$	20,616	$	28,967	$	33,590	$	63,659	$	68,102
Diluted earnings per share before cumulative effect of accounting change		0.42		0.57		0.67		1.23		1.32

Beginning on January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which substantially changed the reporting of the Company’s decommissioning obligation at Palo Verde and Four Corners. During 2003, the Company recognized the effect of this accounting change, which increased net income by $39.6 million, net of tax. The above table compares historical results to pro forma results which assume SFAS No. 143 had been applied in both 2002 and 2001. Income before the cumulative effect of accounting change decreased $13.0 million, or $0.25 diluted earnings per share in 2003 compared to the pro forma results for 2002. This after-tax decrease resulted primarily from (i) decreased wholesale sales revenue of $15.6 million primarily related to the expiration of two long-term contracts; (ii) the impairment loss on the CIS project of $10.7 million; (iii) increased pension and benefits expenses of $3.1 million; (iv) Texas fuel disallowance of $2.8 million; (v) increased insurance expenses of $2.8 million; (vi) increased outside services of $2.2 million; and (vii) increased expense at Palo Verde of $1.3 million. These decreases were partially offset by (i) the 2002 accrual for the FERC settlements of $9.5 million with no comparable amount in 2003; (ii) increased sales and margins on economy sales of $6.3 million; (iii) increased retail sales of $5.6 million; (iv) decreased interest on long-term debt of $2.3 million; (v) decreased loss on extinguishment of debt of $2.1 million; and (vi) decreased MiraSol operating loss of $1.9 million.

Pro forma income before cumulative effect of accounting change decreased $34.5 million or $0.65 diluted earnings per share in 2002 compared to the pro forma results for 2001. This after-tax decrease was primarily due to (i) decreased economy sales margins of $20.3 million related to significantly reduced wholesale prices in the western United States; (ii) the FERC settlements of $9.5 million; (iii) increased demand charges of $4.5 million; (iv) decreased wholesale sales of $3.7 million; (v) increased expense at Palo Verde of $2.8 million; (vi) increased regulatory expense of $2.4 million; (vii) decreased investment performance of $2.1 million; and (viii) a reduction in the estimate of a contingent tax liability in 2001 of $2.5 million with no comparable amount in 2002. These

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decreases were partially offset by (i) the recovery of energy expenses in New Mexico of $6.3 million; (ii) increased retail sales of $5.4 million; and (iii) decreased interest expense on long-term debt of $4.7 million.

Operating revenues net of energy expenses decreased $16.4 million in 2003 compared to 2002 primarily due to (i) decreased wholesale sales of $25.5 million; (ii) Texas fuel disallowance of $4.5 million; and (iii) a $4.0 million decrease in revenue from the energy service operations partially offset by increased sales and margins on economy sales of $10.3 million and increased retail sales of $9.2 million.

Operating revenues net of energy expenses decreased $38.8 million in 2002 compared to 2001 primarily due to (i) decreased economy sales margins of $33.2 million related to the significantly reduced wholesale prices in the western United States; (ii) decreased revenue from the energy services operations of $10.6 million; (iii) increased demand charges of $7.3 million; and (iv) decreased wholesale sales of $6.0 million. This decrease was partially offset by the recovery of energy expenses in New Mexico in 2002 of $10.3 million, with no comparable recovery in 2001 and increased retail sales of $8.8 million.

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

	2003		2002		Increase (Decrease)
Years Ended December 31:					Amount			Percent
kWh sales:
Retail:
Residential		1,932,171		1,870,931		61,240		3.3	%
Commercial and industrial, small		2,096,860		2,076,758		20,102		1.0
Commercial and industrial, large		1,197,065		1,161,815		35,250		3.0
Sales to public authorities		1,224,349		1,212,180		12,169		1.0
Total retail sales		6,450,445		6,321,684		128,761		2.0
Wholesale:
Sales for resale		67,754		986,134		(918,380	)	(93.1	)(1)
Economy sales		1,920,882		1,483,465		437,417		29.5	(2)
Total wholesale sales		1,988,636		2,469,599		(480,963	)	(19.5	)
Total kWh sales		8,439,081		8,791,283		(352,202	)	(4.0	)
Operating revenues:
Base revenues:
Retail:
Residential	$	171,459	$	166,320	$	5,139		3.1	%
Commercial and industrial, small		165,434		163,553		1,881		1.2
Commercial and industrial, large		43,294		43,419		(125	)	(0.3	)
Sales to public authorities		73,136		70,802		2,334		3.3
Total retail base revenues		453,323		444,094		9,229		2.1
Wholesale:
Sales for resale		3,223		32,228		(29,005	)	(90.0	)(1)
Total base revenues		456,546		476,322		(19,776	)	(4.2	)
Fuel revenues		122,761		158,650		(35,889	)	(22.6	)(3)
Economy sales		76,536		43,654		32,882		75.3	(2)
Other		8,519		11,459		(2,940	)	(25.7	)(4)(5)
Total operating revenues	$	664,362	$	690,085	$	(25,723	)	(3.7	)

⁽¹⁾ Primarily due to the expiration of wholesale power contracts with IID on April 30, 2002 and TNP on December 31, 2002, and reduced sales to the CFE.

⁽²⁾ Primarily due to increased available power as a result of the expiration of the wholesale contracts mentioned above and higher prices in the economy market.

⁽³⁾ Primarily due to the expiration of wholesale power contracts with IID and TNP, decreased energy expenses passed through to Texas and New Mexico customers, and reduced sales to the CFE.

⁽⁴⁾ Primarily due to decreased energy services revenues.

⁽⁵⁾ Represents revenues with no related kWh sales.

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	2002		2001		Increase (Decrease)
Years Ended December 31:					Amount			Percent
kWh sales:
Retail:
Residential		1,870,931		1,789,199		81,732		4.6	%
Commercial and industrial, small		2,076,758		2,069,517		7,241		0.3
Commercial and industrial, large		1,161,815		1,174,235		(12,420	)	(1.1	)
Sales to public authorities		1,212,180		1,185,521		26,659		2.2
Total retail sales		6,321,684		6,218,472		103,212		1.7
Wholesale:
Sales for resale		986,134		1,460,383		(474,249	)	(32.5	)(1)
Economy sales		1,483,465		929,914		553,551		59.5	(2)
Total wholesale sales		2,469,599		2,390,297		79,302		3.3
Total kWh sales		8,791,283		8,608,769		182,514		2.1
Operating revenues:
Base revenues:
Retail:
Residential	$	166,320	$	159,263	$	7,057		4.4	%
Commercial and industrial, small		163,553		161,997		1,556		1.0
Commercial and industrial, large		43,419		43,644		(225	)	(0.5	)
Sales to public authorities		70,802		70,372		430		0.6
Total retail base revenues		444,094		435,276		8,818		2.0
Wholesale:
Sales for resale		32,228		52,879		(20,651	)	(39.1	)(1)
Total base revenues		476,322		488,155		(11,833	)	(2.4	)
Fuel revenues		158,650		164,335		(5,685	)	(3.5	)
Economy sales		43,654		92,452		(48,798	)	(52.8	)(3)
Other		11,459		24,763		(13,304	)	(53.7	)(4)(5)
Total operating revenues	$	690,085	$	769,705	$	(79,620	)	(10.3	)

⁽¹⁾ Primarily due to the expiration of a wholesale power contract with IID on April 30, 2002 and decreased sales to CFE, partially offset by increased kWh sales to TNP.

⁽²⁾ Primarily due to increased available power as a result of decreased sales to IID and increased sales at Palo Verde due to transmission constraints.

⁽³⁾ Primarily due to a weaker power market in 2002 compared to the previous year.

⁽⁴⁾ Primarily due to decreased energy services revenues.

⁽⁵⁾ Represents revenues with no related kWh sales.

Other operations expense increased $14.6 million in 2003 compared to 2002 primarily due to (i) increased pension and benefits expense of $5.0 million resulting from declines in the financial markets; (ii) accretion expense of $4.8 million related to the implementation of SFAS No. 143; (iii) increased insurance related expenses of $4.5 million; (iv) increased legal and consulting fees of $3.7 million; and (v) increased Palo Verde expense of $3.4 million. These increases were partially offset by decreased energy services operations expense of $7.2 million primarily due to a warranty reserve recorded by the Company in 2002 and the cessation of additional marketing activities by MiraSol in

33

2002. Other operations expense slightly increased in 2002 compared to 2001 primarily due to increased professional fees related to regulatory matters of $3.9 million and increased Palo Verde expense of $2.9 million, partially offset by decreased energy services operations expenses of $7.7 million due to the cessation of additional marketing activities in 2002.

In July 2002, the Company suspended work on its CIS project to perform an assessment of the project and of alternatives to completion of the project. This assessment included analyzing the impact of potential delays in the implementation of deregulation and resulting changes in billing requirements, and the software’s ability to perform to specification. Based on this assessment and on events related to the project which occurred in 2003, the Company abandoned the CIS project and recognized an asset impairment loss of $17.6 million. The Company is now analyzing various options to meet its current and projected CIS needs.

The FERC settlements relate to the settlements with the FERC Trial Staff and principal California parties pursuant to which the Company agreed to refund $15.5 million of revenues it earned on wholesale power transactions in 2000 and 2001. These settlements were recorded in December 2002.

Maintenance expense increased slightly in 2003 compared to 2002 primarily due to maintenance outages in 2003 at local generating stations of $1.7 million offset by reduced maintenance at Palo Verde of $1.2 million due to timing of scheduled refueling and maintenance outages. Maintenance expense increased $2.0 million in 2002 compared to 2001 primarily due to the timing of refueling and maintenance outages at Palo Verde of $1.8 million.

Depreciation and amortization expense decreased $2.4 million in 2003 compared to 2002 primarily due to decreased depreciation expense of $3.7 million resulting from the implementation of SFAS No. 143. Depreciation and amortization expense remained relatively unchanged in 2002 compared to 2001.

Taxes other than income taxes decreased by $0.5 million in 2003 compared to 2002 due to a decrease in property tax. Taxes other than income taxes remained relatively unchanged in 2002 compared to 2001.

Other income (deductions) increased $6.9 million in 2003 compared to 2002 primarily due to losses on extinguishments of debt of $3.4 million recorded in 2002 with no comparable activity in 2003 and increased investment and interest income of $2.8 million primarily related to the decommissioning trust fund. Other income (deductions) decreased $3.8 million in 2002 compared to 2001 primarily due to a decrease of (i) $1.4 million in interest income on the undercollection of Texas fuel revenues; (ii) $1.1 million on investment income related to the decommissioning trust funds; and (iii) a $0.5 million insurance reimbursement recognized in 2001 with no comparable activity in 2002.

Interest charges decreased $11.8 million in 2003 compared to 2002 primarily due to (i) an $8.3 million decrease resulting from the implementation of SFAS No. 143 and (ii) a $3.5 million decrease resulting from a reduction of outstanding debt as a result of open market purchases and retirements of the Company’s first mortgage bonds. Interest charges decreased $7.8 million in 2002 compared to 2001 primarily due to (i) a $6.7 million decrease resulting from a reduction of outstanding

34

debt as a result of open market purchases of the Company’s first mortgage bonds; (ii) increased capitalized interest related to construction work in progress; and (iii) decreased interest rates.

Income tax expense, excluding the tax effect of a cumulative effect of accounting change, decreased $3.3 million in 2003 compared to 2002, and $18.3 million in 2002 compared to 2001 primarily due to changes in pretax income and certain permanent differences and adjustments.

The cumulative effect of accounting change relates to the adoption of SFAS No. 143 on January 1, 2003. SFAS No. 143 provides guidance on the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. SFAS No. 143 affected the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and changed the method used to report the decommissioning obligation.

In December 2003, the FASB issued FASB Interpretation No. 46 (“FIN 46R”) (revised December 2003), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was issued in January 2003. The Company currently does not have a controlling financial interest in any entities through means other than voting rights and FIN 46R will not have an impact on the Company’s consolidated financial statements.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” was issued in May 2003. This statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The statement also includes required disclosures for financial instruments within its scope. For the Company, the statement was effective for instruments entered into or modified after May 31, 2003 and otherwise will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial instruments, the statement will be effective for the Company on January 1, 2005. The Company currently does not have any financial instruments that are within the scope of this statement.

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The following discussion regarding the Company’s 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.

The Company is exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions held by the Company described below are held for purposes other than trading.

35

Interest Rate Risk

The Company’s long-term debt obligations are all fixed-rate obligations with varying maturities, except for its revolving credit facility, which provides for nuclear fuel financing and working capital, and is based on floating rates. Interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the Texas and New Mexico Commission rules which establish energy cost recovery clauses (“fuel clauses”). See Part I, Item 1, “Regulation – New Mexico Regulatory Matters – New Mexico Stipulation.” Under these rules and fuel clauses, energy costs, including interest expense on nuclear fuel financing, are passed through to customers. Currently, the Company anticipates remarketing its pollution control bonds in 2005 and issuing additional long-term debt in 2006 to retire the then outstanding 8.9% Series D First Mortgage Bonds.

The Company’s decommissioning trust funds consist of equity securities and fixed income instruments and are carried at market value. The Company faces interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $32.8 million and $26.2 million as of December 31, 2003 and 2002, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.5 million and $0.4 million based on their fair values at December 31, 2003 and 2002, respectively.

Equity Price Risk

The Company’s decommissioning trust funds include marketable equity securities of approximately $47.7 million and $33.7 million at December 31, 2003 and 2002, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $9.5 million and $6.7 million based on their fair values at December 31, 2003 and 2002, respectively.

Commodity Price Risk

The Company utilizes contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage its 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 the Company’s 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, the Company’s exposure to fuel and purchased power price risk is substantially mitigated through the operation of the Texas and New Mexico Commission rules and the Company’s fuel clauses, as discussed previously.

In the normal course of business, the Company utilizes contracts of various durations for the forward sales and purchases of electricity to effectively manage its available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when the Company’s available power resources are expected to exceed the requirements of its 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 the Company’s expected incremental power production costs or to supplement the Company’s generating capacity when demand is anticipated to exceed such capacity. As of March 5, 2004, the Company had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, “Business – Energy Sources –

36

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 the Company’s financial statements. Because of the operation of the Texas and New Mexico Commission rules and the Company’s fuel clauses, these contracts do not expose the Company to significant commodity price risk.

37

Item 8. Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

	Page
Independent Auditors’ Report	39
Consolidated Balance Sheets at December 31, 2003 and 2002	40
Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001	42
Consolidated Statements of Comprehensive Operations for the years ended December 31, 2003, 2002 and 2001	43
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2003, 2002 and 2001	44
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001	45
Notes to Consolidated Financial Statements	46

38

INDEPENDENT AUDITORS’ REPORT

The Shareholders and Board of Directors

El Paso Electric Company:

We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2003 and 2002, 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, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note D to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in 2003.

KPMG LLP

El Paso, Texas

March 10, 2004

39

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
(In thousands)	2003		2002
Utility plant:
Electric plant in service	$	1,784,134	$	1,753,022
Less accumulated depreciation and amortization		591,613		565,209
Net plant in service		1,192,521		1,187,813
Construction work in progress		69,175		117,595
Nuclear fuel; includes fuel in process of $6,878 and $9,639, respectively		70,198		74,070
Less accumulated amortization		33,888		34,474
Net nuclear fuel		36,310		39,596
Net utility plant		1,298,006		1,345,004
Current assets:
Cash and temporary investments		34,426		75,142
Accounts receivable, principally trade, net of allowance for doubtful accounts of $3,470 and $3,234, respectively		66,589		66,818
Accumulated deferred income taxes		36,248		28,149
Inventories, at cost		25,321		24,713
Undercollection of fuel revenues		12,399		6,401
Prepayments and other		27,190		11,961
Total current assets		202,173		213,184
Deferred charges and other assets:
Decommissioning trust funds		80,475		59,923
Undercollection of fuel revenues – noncurrent		—		12,404
Other		15,200		16,474
Total deferred charges and other assets		95,675		88,801
Total assets	$	1,595,854	$	1,646,989

See accompanying notes to consolidated financial statements.

40

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)

CAPITALIZATION AND LIABILITIES

	December 31,
(In thousands except for share data)	2003			2002
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 62,487,263 and 62,389,415 shares issued, and 146,489 and 203,046 restricted shares, respectively	$	62,633		$	62,592
Capital in excess of stated value		264,235			262,480
Unearned compensation – restricted stock awards		(878	)		(1,442	)
Retained earnings		354,993			294,742
Accumulated other comprehensive loss, net of tax		(9,613	)		(14,421	)
		671,370			603,951
Treasury stock, 15,070,266 and 12,982,995, shares respectively; at cost		(171,548	)		(147,309	)
Common stock equity		499,822			456,642
Long-term debt, net of current portion		588,536			588,650
Financing obligations, net of current portion		20,186			25,725
Total capitalization		1,108,544			1,071,017
Current liabilities:
Current maturities of long-term debt and financing obligations		22,106			60,961
Accounts payable, principally trade		19,197			24,899
FERC settlements payable		—			15,500
Taxes accrued other than federal income taxes		15,167			17,827
Interest accrued		14,706			15,965
Overcollection of fuel revenues		10,070			—
Other		20,781			20,556
Total current liabilities		102,027			155,708
Deferred credits and other liabilities:
Asset retirement obligation (see Note D)		55,149			145,871
Accumulated deferred income taxes		139,605			97,084
Accrued postretirement benefit liability		94,510			88,569
Accrued pension liability		53,000			51,086
Other		43,019			37,654
Total deferred credits and other liabilities		385,283			420,264
Commitments and contingencies
Total capitalization and liabilities	$	1,595,854		$	1,646,989

See accompanying notes to consolidated financial statements.

41

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except for share data)

	Years Ended December 31,
	2003			2002			2001
Operating revenues	$	664,362		$	690,085		$	769,705
Energy expenses:
Fuel		165,367			132,413			185,449
Purchased and interchanged power		55,592			97,825			85,587
		220,959			230,238			271,036
Operating revenues net of energy expenses		443,403			459,847			498,669
Other operating expenses:
Other operations		167,497			152,917			152,376
Impairment loss on CIS project		17,576			—			—
FERC settlements		—			15,500			—
Maintenance		48,246			48,022			46,009
Depreciation and amortization		87,141			89,582			89,462
Taxes other than income taxes		42,728			43,219			43,220
		363,188			349,240			331,067
Operating income		80,215			110,607			167,602
Other income (deductions):
Investment and interest income (loss), net		1,840			(990	)		2,453
Loss on extinguishments of debt		(1	)		(3,410	)		(3,634	)
Other, net		(1,496	)		(2,195	)		(1,576	)
		343			(6,595	)		(2,757	)
Income before interest charges		80,558			104,012			164,845
Interest charges (credits):
Interest on long-term debt and financing obligations		51,400			55,160			62,902
Other interest		695			8,835			7,998
Interest capitalized		(5,572	)		(5,641	)		(4,723	)
		46,523			58,354			66,177
Income before income taxes and cumulative effect of accounting change		34,035			45,658			98,668
Income tax expense		13,419			16,691			35,009
Income before cumulative effect of accounting change		20,616			28,967			63,659
Cumulative effect of accounting change, net of tax		39,635			—			—
Net income	$	60,251		$	28,967		$	63,659
Basic earnings per share:
Income before cumulative effect of accounting change	$	0.42		$	0.58		$	1.25
Cumulative effect of accounting change, net of tax		0.82			—			—
Net income	$	1.24		$	0.58		$	1.25
Diluted earnings per share:
Income before cumulative effect of accounting change	$	0.42		$	0.57		$	1.23
Cumulative effect of accounting change, net of tax		0.81			—			—
Net income	$	1.23		$	0.57		$	1.23
Weighted average number of shares outstanding		48,424,212			49,862,417			50,821,140
Weighted average number of shares and dilutive potential shares outstanding		48,814,761			50,380,468			51,722,351

See accompanying notes to consolidated financial statements.

42

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)

	Years Ended December 31,
	2003			2002			2001
Net income	$	60,251		$	28,967		$	63,659
Other comprehensive income (loss):
Minimum pension liability adjustment		(4,234	)		(21,148	)		(824	)
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period		8,764			(7,657	)		(5,611	)
Reclassification adjustments for net losses included in net income		722			4,245			3,089
Total other comprehensive income (loss) before income taxes		5,252			(24,560	)		(3,346	)
Income tax benefit (expense) related to items of other
comprehensive income (loss):
Minimum pension liability adjustment		1,673			8,193			313
Net unrealized gains (losses) on marketable securities		(2,117	)		1,194			883
Total income tax benefit (expense)		(444	)		9,387			1,196
Other comprehensive income (loss), net of tax		4,808			(15,173	)		(2,150	)
Comprehensive income	$	65,059		$	13,794		$	61,509

See accompanying notes to consolidated financial statements.

43

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			Unearned Compensation – Restricted Stock Awards			Retained Earnings		Accumulated Other Comprehensive Income (Loss), Net of Tax			Treasury Stock			Total Common Stock Equity
	Shares		Amount
Balances at December 31, 2000	60,705,173		$	60,705		$	244,528		$	(1,309	)	$	202,116	$	2,902		$	(96,908	)	$	412,034
Grants of restricted common stock	187,270			187			2,410			(2,597	)										—
Stock options exercised or remeasured	1,396,045			1,396			7,309														8,705
Amortization of unearned compensation										1,835											1,835
Stock awards withheld for taxes	(34,995	)		(35	)		(416	)													(451	)
Forfeitures of restricted common stock	(3,196	)		(3	)		(27	)		30											—
Deferred taxes on stock incentive plan							41														41
Adjustment to state income tax valuation allowance							4,046														4,046
Net income													63,659								63,659
Other comprehensive loss															(2,150	)					(2,150	)
Treasury stock acquired, 2,760,851 shares; at cost																		(37,526	)		(37,526	)
Balances at December 31, 2001	62,250,297			62,250			257,891			(2,041	)		265,775		752			(134,434	)		450,193
Grants of restricted common stock	109,240			109			1,477			(1,586	)										—
Stock options exercised or remeasured	280,000			280			1,966														2,246
Amortization of unearned compensation										1,865											1,865
Stock awards withheld for taxes	(23,727	)		(24	)		(312	)													(336	)
Forfeitures of restricted common stock	(23,349	)		(23	)		(297	)		320											—
Deferred taxes on stock incentive plan							(553	)													(553	)
Adjustment to federal valuation allowance							2,308														2,308
Net income													28,967								28,967
Other comprehensive loss															(15,173	)					(15,173	)
Treasury stock acquired, 991,358 shares; at cost																		(12,875	)		(12,875	)
Balances at December 31, 2002	62,592,461			62,592			262,480			(1,442	)		294,742		(14,421	)		(147,309	)		456,642
Grants of restricted common stock	63,090			63			661			(724	)										—
Amortization of unearned compensation										1,288											1,288
Stock awards withheld for taxes	(21,799	)		(22	)		(209	)													(231	)
Deferred taxes on stock incentive plan							1,008														1,008
Adjustment to federal valuation allowance							295														295
Net income													60,251								60,251
Other comprehensive income															4,808						4,808
Treasury stock acquired, 2,087,271 shares; at cost																		(24,239	)		(24,239	)
Balances at December 31, 2003	62,633,752		$	62,633		$	264,235		$	(878	)	$	354,993	$	(9,613	)	$	(171,548	)	$	499,822

See accompanying notes to consolidated financial statements.

44

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2003			2002			2001
Cash Flows From Operating Activities:
Net income	$	60,251		$	28,967		$	63,659
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		87,141			89,582			89,462
Impairment loss on CIS project		17,576			—			—
Amortization of nuclear fuel		16,374			17,968			16,272
Cumulative effect of accounting change, net of tax		(39,635	)		—			—
Deferred income taxes, net		10,249			2,515			31,655
Loss on extinguishments of debt		1			3,410			3,634
Other amortization and accretion		7,744			11,703			11,279
Other operating activities		1,432			2,918			2,261
Change in:
FERC settlements payable		(15,500	)		15,500			—
Accounts receivable		(1,258	)		8,207			11,622
Inventories		(366	)		(357	)		489
Net under/overcollection of fuel revenues		16,476			4,727			2,044
Prepayments and other		(17,687	)		(2,220	)		10,871
Accounts payable		(5,702	)		273			(15,173	)
Taxes accrued other than federal income taxes		(2,660	)		1,674			(901	)
Interest accrued		(1,259	)		(895	)		332
Other current liabilities		225			4,054			1,534
Deferred charges and credits		1,612			2,281			6,312
Net cash provided by operating activities		135,014			190,307			235,352
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment		(77,080	)		(65,065	)		(70,739	)
Cash additions to nuclear fuel		(13,848	)		(16,036	)		(17,031	)
Interest capitalized:
Utility property, plant and equipment		(5,322	)		(5,290	)		(4,246	)
Nuclear fuel		(250	)		(351	)		(477	)
Decommissioning trust funds:
Purchases		(21,079	)		(19,308	)		(21,791	)
Sales and maturities		9,384			14,190			16,772
Other investing activities		1,467			(469	)		101
Net cash used for investing activities		(106,728	)		(92,329	)		(97,411	)
Cash Flows From Financing Activities:
Proceeds from exercise of stock options		—			2,006			8,275
Purchases of treasury stock		(24,239	)		(12,875	)		(37,526	)
Repurchases of and payments on first mortgage bonds		(39,360	)		(36,344	)		(91,555	)
Pollution control bonds:
Proceeds		—			70,400			—
Payments		—			(70,400	)		—
Nuclear fuel financing obligations:
Proceeds		15,169			18,235			19,468
Payments		(20,207	)		(19,310	)		(19,336	)
Other financing activities		(365	)		(2,542	)		(617	)
Net cash used for financing activities		(69,002	)		(50,830	)		(121,291	)
Net increase (decrease) in cash and temporary investments		(40,716	)		47,148			16,650
Cash and temporary investments at beginning of period		75,142			27,994			11,344
Cash and temporary investments at end of period	$	34,426		$	75,142		$	27,994

See accompanying notes to consolidated financial statements.

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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 wholesale customers in Texas and periodically in the Republic of Mexico.

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 marketing 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 I. 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”). The Company previously determined that it does not meet the criteria for the application of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and accordingly does not currently report the effects of certain actions of regulators as assets or liabilities unless such actions result in assets or liabilities under generally accepted accounting principles for commercial enterprises in general. The Company continues to review whether, on a prospective basis, it may meet the criteria for applying SFAS No. 71 to its general purpose financial statements for some or all of its operations.

Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported as other comprehensive income in accordance with 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 5 to 31 years), except for approximately $298 million of reorganization value allocated primarily to net transmission, distribution and general plant in service. This amount is being depreciated over the ten-year period of the Texas Rate Stipulation, which ends August 2005. For all other utility plant, Texas and New Mexico depreciation lives are the same. Amortization of intangible

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plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 10 years).

The Company charges the cost of repairs and minor replacements to the appropriate operating expense accounts and capitalizes the cost of renewals and betterments. Gains or losses resulting from retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation.

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 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 C.

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 estimate 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.

Capitalized Interest. The Company capitalizes interest cost to construction work in progress and nuclear fuel in process in accordance with SFAS No. 34, “Capitalization of Interest Cost.”

Asset Retirement Obligation. Effective January 1, 2003, the Company adopted 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 increase in the ARO due to the passage of time is recorded as an operating expense (accretion expense). See Note D.

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

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Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair market value and consist primarily of 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. See Note M.

Inventories. Inventories, primarily parts, materials, supplies and fuel oil 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 presently being billed under a fixed fuel factor approved by the Texas Commission. As of June 2003, the Company’s New Mexico retail customers are being billed under a fuel adjustment clause which is adjusted monthly, pending a final order from the New Mexico Commission in the Company’s July 2003 rate compliance filing. 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 the Company’s Texas and New Mexico customers, as determined under Texas and New Mexico Commission rules, is reflected as net over/undercollection of fuel revenues in the balance sheets. See Note B.

Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2003, 2002 and 2001 are as follows (in thousands):

	2003		2002		2001
Balance at beginning of year	$	3,234	$	3,525	$	3,325
Additions:
Charged to costs and expense		3,096		2,909		3,962
Charged to other accounts (1)		981		835		689
Deductions (2)		3,841		4,035		4,451
Balance at end of year	$	3,470	$	3,234	$	3,525

⁽¹⁾ Recovery of amounts previously written off.

⁽²⁾ Uncollectible receivables written off.

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated future tax consequences of “temporary differences” by applying enacted

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statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. The Company records a valuation allowance to reduce its deferred tax assets to the extent it is more likely than not that such deferred tax assets will not be realized. 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.

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 stock options which were outstanding during the period calculated by the treasury stock method and unvested restricted stock.

Stock Options and Restricted Stock. The Company has two stock-based long-term incentive plans and accounts for them under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Stock options have typically been granted with an exercise price equal to fair market value on the date of grant and, accordingly, no compensation expense is recorded by the Company. Restricted stock has been granted at fair market value. Accordingly, the Company recognizes compensation expense by ratably amortizing the fair market value of the grant over the restriction period. If compensation expense for the option portion of the plans had been determined based on the fair value of the option at the grant date and amortized on a straight-line basis over the vesting period, consistent with the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company’s net earnings and earnings per share would have been reduced to the pro forma amounts presented below:

	Years Ended December 31,
	2003		2002		2001
Net income, as reported	$	60,251	$	28,967	$	63,659
Deduct: Compensation expense, net of tax		916		1,326		1,384
Pro forma net income	$	59,335	$	27,641	$	62,275
Basic earnings per share:
As reported	$	1.24	$	0.58	$	1.25
Pro forma		1.22		0.55		1.23
Diluted earnings per share:
As reported		1.23		0.57		1.23
Pro forma		1.22		0.55		1.20

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The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. Weighted average assumptions and grant-date fair value for 2003, 2002 and 2001 are presented below:

	2003			2002			2001
Risk-free interest rate		4.13	%		5.22	%		5.06	%
Expected life, in years		7.4			10			10
Expected volatility		24.72	%		26.10	%		27.92	%
Expected dividend yield		—			—			—
Fair value per option	$	4.83		$	6.75		$	7.18

Compensation expense for the restricted stock awards is recognized on a fair value basis and is measured by referencing the quoted market price of the shares at the grant date, amortized ratably over the restriction period. Unearned compensation related to restricted stock awards is shown as a reduction of common stock equity.

Other New Accounting Standards. During 2003, the Company adopted SFAS No. 132 (revised 2003), “Employers’ Disclosure about Pensions and Other Postretirement Benefits,” SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” SFAS No. 148, “Accounting for Stock-based Compensation Transition and Disclosure, an Amendment of FASB Statement No. 123,” SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” and FASB Interpretation No. 45, “Guarantors’ Accounting and Disclosure Requirements of Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57, and 107 and a Rescission of FASB Interpretation No. 34” and certain provisions of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” The implementation of these standards did not have a significant impact on the Company’s financial position or results of operations.

Additionally, during 2003, the Company adopted SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections.” SFAS No. 145 required the Company to classify gains and losses on the extinguishment of debt in other income (deductions) and the Company reclassified prior period amounts to conform with this presentation.

Reclassification. Certain amounts in the consolidated financial statements for 2002 and 2001 have been reclassified to conform with the 2003 presentation.

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B. Regulation

General

In 1999, both the Texas and New Mexico legislatures enacted electric utility industry restructuring laws requiring competition in certain functions of the industry and ultimately in the Company’s service area. In Texas, the Company is exempt from the requirements of the Texas Restructuring Law, including utility restructuring and retail competition, until the expiration of the Freeze Period in August 2005. In April 2003, the New Mexico Electric Utility Industry Restructuring Act of 1999 (“New Mexico Restructuring Act”) was repealed and as a result, the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas. However, the Company believes that the New Mexico Commission will have to approve the separation of the Company’s operations if and when the Company implements utility restructuring and retail competition for compliance with the Texas Restructuring Law.

Federal Regulatory Matters

Federal Energy Regulatory Commission. The FERC has been conducting an investigation into potential manipulation of electricity prices in the western United States during 2000 and 2001. On August 13, 2002, the FERC initiated a Federal Power Act (“FPA”) investigation into the Company’s wholesale power trading in the western United States during 2000 and 2001 to determine whether the Company engaged in misconduct and, if so, to determine potential remedies. The Company reached settlements with the FERC and other parties in 2002 and 2003. Under the terms of the settlements, the Company agreed to refund a total of $15.5 million of revenues it earned on wholesale power transactions. In July 2003, the FERC approved the settlements and on August 5, 2003, the Company deposited the $15.5 million into an interest bearing escrow account to consummate the settlements. The Company believes the FERC’s order resolved all issues between the FERC and the other parties to this investigation. Under the settlements, the Company has agreed to make wholesale sales pursuant to its cost of service rate authority rather than its market-based rate authority for the period December 1, 2002 through December 31, 2004. This agreement allows the Company to sell power into wholesale markets at its incremental cost plus $21.11 per MWh. To the extent that wholesale market prices exceed these agreed upon amounts, the Company will forego the opportunity to realize these additional revenues. Although this provision has not had a significant impact on the Company’s revenues through December 31, 2003, the Company is unable to predict the effect, if any, this will have on the Company’s 2004 revenues.

RTOs. FERC’s rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”) strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. As a participating transmission owner, the Company will ultimately transfer

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operational authority of its transmission system to WestConnect subject to receiving any necessary regulatory approvals. On October 10, 2002, FERC issued an order indicating that the Company’s WestConnect proposal satisfied, or with certain modifications would satisfy, the FERC requirements for an RTO under Order 2000. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company, however, is anticipated to be no more than a 9% participant in WestConnect and cannot control the terms or timing of its establishment. WestConnect will not be operational before the end of the Freeze Period. The establishment of an RTO in the Company’s service area is an important factor in the Company’s ability to establish a Qualified Power Region as defined in the Texas Restructuring Law and the timing of the operations of WestConnect could affect when and whether the Company’s Texas service territory participates in the Texas deregulated market.

Department of Energy. The DOE regulates the Company’s exports of power to the Comision Federal de Electricidad de Mexico (“CFE”) 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 Note C for discussion of spent fuel storage and disposal costs.

Nuclear Regulatory Commission. The Nuclear Regulatory Commission (“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 conduct environmental reviews pursuant to the National Environmental Policy Act.

Texas Regulatory Matters

The rates and services of the Company are regulated in Texas by municipalities and by the Texas Commission. The largest municipality in the Company’s service area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services within municipalities in Texas and original jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.

Deregulation. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation 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. The Texas Restructuring Law, however, specifically recognized and preserved the Company’s Texas Rate Stipulation and Texas Settlement Agreement by, among other things, exempting the Company’s Texas service area from retail competition until the end of the Freeze Period. The Texas Commission recently opened a project (Project No. 28971) to evaluate the readiness of the Company’s service area in Texas for retail competition for generation services. In this project, the Texas Commission may specify in

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advance the factors that are important in deciding when and whether to open the Company’s service area in Texas to customer choice. One of the key factors that will likely be utilized by the Texas Commission in its determination is the progress that has been made in developing an RTO in the Company’s service area. Public hearings to discuss the readiness of the Company’s service area were held on March 4, 2004 in El Paso and will be held in Austin in April 2004. 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 will not adversely affect the future operations, cash flows and financial condition of the Company.

Fuel. Although the Company’s base rates are frozen in Texas, pursuant to Texas Commission rules and the Texas Rate Stipulation, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with providing electricity and seek recovery of past undercollections of fuel revenues, subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.

On March 10, 2004, the Texas Commission announced its decision in PUC Docket No. 26194, a case in which the Company sought to reconcile its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge because of fuel undercollections from January 1999 through December 2001. The Texas Commission disallowed approximately $4.5 million of Texas jurisdictional expenses, before interest, consisting primarily of (i) approximately $4.2 million of purchased power expenses which the Texas Commission characterized as “imputed capacity charges,” and (ii) approximately $0.3 million in fees which were deemed to be administrative costs, not recoverable as fuel. In Texas, capacity charges are not eligible for recovery as fuel expenses, but are to be recovered through the Company’s base rates. As the Company’s base rates were frozen during the time period in question, the $4.2 million of “imputed capacity charges” would be permanently disallowed, and hence not recoverable from its Texas customers.

The Texas Commission’s decision modifies the Proposal for Decision issued September 19, 2003 by the Administrative Law Judges (“ALJs”). The ALJs had recommended that approximately $21.2 million of the Company’s purchased power expense should be disallowed as imputed capacity charges and not recovered from Texas jurisdictional customers.

The Company has incurred similar purchased power costs for the fuel reconciliation period beginning January 1, 2002. The Company believes that it has accounted for its purchased power costs during the reconciliation period beginning January 2002 in a manner consistent with the Texas Commission’s decision in PUC Docket No. 26194. However, the Texas Commission has indicated its desire to conduct a generic rulemaking proceeding to determine a statewide policy for the appropriate pricing of capacity in purchased power contracts. There can be no assurance, however, as to the

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outcome of such rulemaking and the potential impact on the Company with respect to fuel recovery in future reconciliation periods if the Texas Commission adopts a different methodology in a subsequent rulemaking proceeding.

The Texas Commission’s decision is subject to appeal by the various parties and the Company is unable to predict the ultimate outcome of any appeals that may be filed in this case.

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 24-month period, should fall below 35%, the Texas Commission can also reconsider the rate treatment of Palo Verde, regardless of the provisions of the Texas Rate Stipulation and the Texas Settlement Agreement. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. Under the performance standards as modified by the Texas Fuel Settlement, the Company has calculated the performance awards for the reporting periods ending in 2003, 2002 and 2001 to be approximately $0.8 million, $1.3 million and $1.1 million, respectively. These rewards will be included, along with energy costs incurred and revenues billed, as part of the Texas Commission’s review during a future periodic fuel reconciliation proceeding 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 are recorded when assessed as probable by the Company.

Texas Renewable Energy Requirement. Chapter 39 of the Public Utility Regulatory Act (“PURA”), implemented by Senate Bill 7 in the 1999 legislative session, requires that, by January 1, 2009, an additional 2,000 MW of generating capacity from renewable energy technologies be installed in the state. The renewable energy requirement is to be added in increments with the cumulative installed renewable capacity in Texas totaling 1,703 MW by January 1, 2005, 2,280 MW by January 1, 2007, and 2,880 MW by January 1, 2009. The requirements of this goal are placed on retail electric providers (“REPs”) who provide competitive retail electric service in the state of Texas. Utilities that have not implemented retail competition may have renewable energy requirements based on orders of the Texas Commission.

Until the end of the Freeze Period, the Company is exempt from PURA Chapter 39 and Texas Commission rules implementing the renewable requirements. However, once the Freeze Period ends, any renewable energy requirement applicable to the Company could be based on the percentage of the competitive retail load that will be served by the Company (or the Company’s REP) in relation to the total competitive retail load served in Texas. It is not clear when the Company will need to meet a renewable energy requirement in Texas or what the obligation will be. The Company is currently reviewing the outcome of its New Mexico RFPs, for renewable energy to assess possible scenarios for

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meeting possible future Texas requirements, which includes the purchase of renewable power and/or credits.

New Mexico Regulatory Matters

The New Mexico Commission has jurisdiction over the Company’s rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Mexico Commission’s decisions are subject to judicial review. The largest city in the Company’s New Mexico service territory is Las Cruces.

Deregulation. In April 2003, the New Mexico Restructuring Act was repealed and as a result the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas.

Fuel. In June 2001, the New Mexico Commission approved a fuel and purchased power cost adjustment clause. On May 31, 2003, the Company submitted a rate compliance filing whereby the Company proposed to continue a base rate recovery of $0.01949 per kWh and continue the fuel and purchased power cost adjustment to recover the remainder of fuel and purchased power costs. The Company and all intervenors entered into the New Mexico Stipulation on the Company’s compliance filing.

New Mexico Rate Stipulation. On January 21, 2004, the Company and all intervenors to the rate compliance filing entered into and filed the New Mexico Stipulation whereby, among other things, the Company agreed for a period of three years beginning June 1, 2004 to (i) freeze base rates after an initial non-fuel base rate reduction of 1%; (ii) fix fuel and purchased power costs associated with 10% of the Company’s jurisdictional retail sales in New Mexico at $0.021 per kWh; (iii) leave subject to reconciliation the remaining 90% of the Company’s New Mexico jurisdictional fuel and purchased power costs; (iv) continue the collection of a portion of fuel and purchased power costs in base rates as presently collected in the amount of $0.01949 per kWh; (v) price power provided from Palo Verde Unit 3 to the extent of its availability at an 80% nuclear, 20% gas fuel mix (currently such power is priced at 75% nuclear, 25% gas fuel mix) and (vi) deem reconciled, for the period June 15, 2001 through May 31, 2004, the Company’s fuel and purchased power costs for the New Mexico jurisdiction. The New Mexico Stipulation is subject to the New Mexico Commission’s approval. The New Mexico Commission hearing on the New Mexico Stipulation was held on February 25, 2004. The Company anticipates a ruling on the New Mexico Stipulation prior to June 2004 with the new rates implemented on or about June 1, 2004. The Company cannot predict the outcome of these proceedings or how the New Mexico Commission will rule.

New Mexico Renewable Energy Requirement. The New Mexico Commission has adopted renewable energy portfolio requirements and has mandated that 5% of all New Mexico retail

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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jurisdictional energy sales in 2006 be supplied by renewable resources or certificates. The renewable portfolio standard increases by 1% each year until 2011, and is set at 10% in 2011 and thereafter. In February 2004, the Company issued a RFP for renewable energy from certified renewable sources to meet the renewable energy portfolio requirements. Based on responses to the RFP, the Company will develop a plan to meet the New Mexico Commission’s renewable energy requirements. In the 2004 New Mexico legislative session, the Renewable Energy Act was enacted which directs the New Mexico Commission to adopt a rule consistent with the law, and required rate recovery for the reasonable costs of compliance with the renewable requirements.

Sales for Resale

The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. No such notice has been received. The Company also made sales of interruptible energy to CFE during the months of June and July 2003 of 13,711 MWh and 4,525 MWh, respectively.

C. Palo Verde and Other Jointly-Owned Utility Plant

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. APS serves as operating agent for 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”).

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. 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.

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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, at December 31, 2003 and 2002 is as follows (in thousands):

	December 31, 2003						December 31, 2002
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	588,071	(1)	$	187,036		$	611,580		$	184,429
Accumulated depreciation		(108,765	)(1)		(113,845	)		(139,271	)		(99,136	)
Construction work in progress		23,251			2,729			46,761			3,649

⁽¹⁾ The decline in these balances is primarily the result of the implementation of SFAS No. 143 at January 1, 2003. See Note D.

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’s decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS.

In accordance with the ANPP Participation Agreement, the Company is required to establish 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. In January 2003, the Company made an additional deposit of $4.7 million into the decommissioning trust fund such that the trust fund met ANPP minimum accumulation levels at December 31, 2002. The Company remained above its minimum funding level as of December 31, 2003. 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.

The Company has established external trusts with independent trustees, which enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded. As of December 31, 2003 and 2002, the fair market value of the trust funds was approximately $80.5 million and $59.9 million, respectively, which is reflected in the Company’s balance sheets in deferred charges and other assets.

In August 2002, the Palo Verde Participants approved the 2001 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 1998 study and the 2001 study. The 2001 study estimated that the Company must fund approximately $311.6 million (stated in 2001 dollars) to cover its share of decommissioning costs. The previous cost estimate from the 1998 study estimated that the Company would fund approximately $280.5 million (stated in 1998 dollars). The 2001 estimate reflects an 11.1% increase, or 3.6% average annual compound increase, from the 1998 estimate

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

primarily due to increases in estimated costs for site restoration at each unit, pre and post-shutdown transitioning and decommissioning preparations, spent fuel storage after operations have ceased and the Unit 2 steam generator storage. The decommissioning study is stated in 2001 dollars and makes no inflation assumptions. See “Spent Fuel Storage” below.

Although the 2001 study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not continue to 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. The decommissioning study is updated every three years and a new study is expected to be completed in 2004. See “Disposal of Low-Level Radioactive Waste” below.

Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under the Texas Restructuring Law, which, among other things, deregulates generation services, the Company, through an affiliated transmission and distribution utility, will be able to collect from customers the costs of decommissioning. The collection mechanism utilized in Texas is a “non-bypassable wires charge” through which all customers, even those who choose to purchase energy from a supplier other than the Company’s retail affiliate, will be required to pay a fee, which includes the cost of nuclear decommissioning, to the Company’s affiliate transmission and distribution utility. In the Company’s case, collection of the fee through the Company’s transmission and distribution utility will begin in Texas if and when retail competition is implemented in the Company’s Texas service territory. See Note B for further discussion.

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 are stored at the new facilities until it is accepted by the DOE for permanent disposal. The 2003 decommissioning study assumes that costs to store fuel on-site will become the responsibility of the DOE after 2037.

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 until 2010. 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.

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The Company expects to incur significant on-site spent fuel storage costs during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs will be amortized over the burn period of the fuel that will necessitate the use of the alternative on-site storage facilities 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. The Company is unable to predict the outcome of these matters 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. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository.

Steam Generators. Palo Verde has experienced degradation in the steam generator tubes of each unit. The projected service lives of the Palo Verde steam generators are reassessed by APS periodically in conjunction with inspections made during scheduled outages at the Palo Verde units. New steam generators were installed at Unit 2 during 2003 at an estimated total cost to the Company of $47.1 million. This replacement was based on an analysis of the net economic benefit from expected improved performance of the unit and the need to realize continued production from that unit over its full licensed life.

APS has identified accelerated degradation in the steam generator tubes in Units 1 and 3 and has concluded that it is economically desirable to replace the steam generators at those units. While analyses related to timing of installation of steam generators at Units 1 and 3 are ongoing, the Company and the other participants approved the expenditure of $202.1 million (the Company’s portion being $31.9 million) for fabrication and transport of steam generators for Units 1 and 3. In addition, APS has proposed, and the participants have approved the expenditure of $28.4 million (the Company’s portion being $4.5 million) for pre-installation and power uprate work for Units 1 and 3. In addition to these approved amounts, the installation of the Units 1 and 3 replacement steam generators and the completion of power uprates at those units will require the expenditure of $278.6 million (the Company’s portion being $44.0 million). Present plans are for replacement steam generators to be installed at Units 1 and 3 in 2005 and 2007, respectively.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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The eventual total cash expenditures for steam generator replacement for Units 1, 2 and 3 is currently estimated to be $718.9 million excluding replacement power costs (the Company’s portion being $113.6 million). As of December 31, 2003, the Company has paid approximately $46.7 million of such costs. The remaining balance is expected to be paid over the course of the steam generator replacements. The Company expects its portion will be funded with internally generated cash.

The Texas Rate Stipulation precludes the Company from seeking a rate increase to recover additional capital costs incurred at Palo Verde during the Freeze Period. The Company cannot assure that its wholesale power rates and its competitive retail rates will be sufficient to recover its costs when or if retail competition for generation services begins.

Liability and Insurance Matters. In 1957, Congress enacted the Price-Anderson Act as an amendment to the Atomic Energy Act of 1954 to provide a system of financial protection for persons who may be injured or persons who may be liable for a nuclear incident. The Price-Anderson Act expired on December 31, 2003. Existing licensees, such as the Company, are grandfathered and will continue to be subject to the provisions of the Price-Anderson Act in the event Congress does not reauthorize the Price-Anderson Act. The Price-Anderson Amendments Act of 2003 has been placed on the legislative calendar under general order (Calendar No. 422). If passed the Act will amend the Atomic Energy Act to: (i) increase from $63 million to $94 million the maximum amount of standard deferred premiums charged a licensee following any nuclear incident under an industry retrospective rating plan; and (ii) increase from $10 million to $15 million (adjusted for inflation) in any one year the maximum amount of such premiums for each facility for which the licensee must maintain the maximum amount of primary financial protection. The amount of DOE indemnification currently available under the act is $9.4 billion. Additionally, the Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under the Price-Anderson Act. The insurance consists of $200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay a retrospective assessment to cover any loss in excess of $200 million. Presently, the maximum retrospective assessment per reactor for each nuclear incident is approximately $88.1 million, subject to an annual limit of $10 million per incident. Based upon the Company’s 15.8% interest in Palo Verde, the Company’s maximum potential retrospective assessment per incident is approximately $41.8 million for all three units with an annual payment limitation of approximately $4.7 million.

The Palo Verde Participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company also has obtained insurance against a portion of any increased cost of generation or purchased power which may result from an accidental outage of any of the three Palo Verde units if the outage exceeds 12 weeks.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

D. Accounting for Asset Retirement Obligations

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The adoption of SFAS No. 143 primarily affected the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and changed the method used to report the decommissioning obligation. Upon emergence from bankruptcy in 1996, the Company was required under fresh-start reporting to adopt the concepts of an early exposure draft of the SFAS No. 143 project and accordingly, recognized the present value of its projected Palo Verde asset retirement costs as both a component of its capitalized cost of Palo Verde and as a decommissioning liability. Subsequently, the Company recognized accretion of the Palo Verde ARO liability as a component of interest expense and depreciation of the Palo Verde asset retirement cost as depreciation expense in its consolidated financial statements. Upon adoption of SFAS No. 143, the net difference between the amounts determined under SFAS No. 143 and the Company’s previous method of accounting for such activities was recognized as a decrease in the ARO of $95.5 million, a decrease in net plant in service of $30.9 million, and a cumulative effect of accounting change of $39.6 million, net of related taxes of $25.0 million. The cumulative effect of accounting change is primarily due to two factors: (i) using a longer discount period (i.e. longer remaining life) as a result of assessing the probability of a license extension at Palo Verde and (ii) a change in the discount rate used. As the DOE assumes 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 independent trustees which are legally restricted to settling its ARO at Palo Verde. The fair value of the fund at December 31, 2003 is $80.5 million.

A reconciliation of the Company’s ARO liability for Palo Verde and Four Corners Stations for the twelve months ended December 31, 2003 is as follows (in thousands):

January 1, 2003	$	50,364
Liabilities incurred		—
Liabilities settled		—
Revisions to estimate		—
Accretion expense		4,785
December 31, 2003	$	55,149

As of December 31, 2002 and 2001, the pro forma ARO liability would have been $50.4 million and $46.0 million, respectively.

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. Additionally, the Company has certain components of its local generating stations which may result in

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

an ARO. However, substantial uncertainty exists surrounding the ultimate removal date for these facilities. Due to the nature of these assets and the uncertainty of final removal timing and costs, an ARO has not been included for these assets as the ARO cannot be reasonably estimated at this time.

Amounts recorded under SFAS No. 143 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 risk-free 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. 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 Company’s most recent Palo Verde decommissioning study, completed in 2001, estimates that the Company’s share of Palo Verde decommissioning costs would be approximately $311.6 million, in year 2001 dollars. This estimated liability differs from the ARO liability of $55.1 million recorded by the Company as of December 31, 2003. This difference can be attributed to how SFAS No. 143 measures the ARO liability, relative to current cost estimates, and the inherent assumption in SFAS No. 143 that Palo Verde will operate until the end of its useful life (which includes an assessment of the probability of a license extension). The ARO liability calculation begins with the same current cost estimate referenced above, then escalates that cost over the remaining life of the plant, finally discounting the resulting cost at 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 its calculation of the ARO liability, the ARO liability is significantly less than the Company’s share of the current estimated cost to decommission Palo Verde in 2001 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.

E. Common Stock

Overview

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

Long-Term Incentive Plans

The Company shareholders have approved the adoption of two stock-based long-term incentive plans. The first plan was approved in 1996 (the “1996 Plan”) and authorized the issuance of up to 3.5 million shares of common stock for the benefit of officers, key employees and directors. The second

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

plan was approved in 1999 (the “1999 Plan”) and authorized the issuance of up to two million shares of common stock for the benefits of directors, officers, managers, other employees and consultants. The 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 and performance stock.

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 options expire ten years from the date of grant unless terminated earlier by the Board of Directors. The following table summarizes the transactions of the Company’s stock options for 2003, 2002 and 2001:

	Number of Shares		Weighted Average Exercise Price
Unexercised options outstanding at December 31, 2000	2,944,848		$	6.86
Options granted	706,677			14.04
Options exercised	(1,396,045	)		5.93
Unexercised options outstanding at December 31, 2001	2,255,480			9.64
Options granted	257,257			13.39
Options exercised	(280,000	)		8.02
Options forfeited	(20,000	)		8.75
Unexercised options outstanding at December 31, 2002	2,212,737			10.40
Options granted	108,717			12.67
Options forfeited	(150,000	)		12.60
Unexercised options outstanding at December 31, 2003	2,171,454			10.36

Stock option awards provide for vesting periods of up to six years. Stock options outstanding and exercisable at December 31, 2003 are as follows:

	Options Outstanding				Options Exercisable
Exercise Price Range	Number Outstanding	Average Remaining Contractual Life in Years	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$ 5.56 - $9.8125	1,093,076	3.3	$	7.03	1,057,076	$	6.97
10.375 - 15.99	1,078,378	8.1		13.74	268,378		13.87
	2,171,454				1,325,454

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The number of stock options exercisable and the weighted average exercise price of these stock options at December 31, 2003, 2002 and 2001 are as follows:

	December 31,
	2003		2002		2001
Number of stock options exercisable		1,325,454		1,183,737		1,233,480
Weighted average exercise price	$	8.36	$	8.04	$	7.55

Restricted Stock. The Company has awarded vested and unvested restricted stock awards under the 1996 and 1999 Plans. Restrictions from resale generally lapse, and unvested awards vest, over periods of four to five 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 time of grant is recorded as unearned compensation as a separate component of common stock equity and is amortized to expense over the restriction period. During 2003, 2002 and 2001, approximately $1.3 million, $1.9 million and $1.8 million, respectively, related to restricted stock awards was charged to expense. The following table summarizes the vested and unvested restricted stock awards for 2003, 2002 and 2001:

	Vested		Unvested		Total
Restricted shares outstanding at December 31, 2000	90,027		186,039		276,066
Restricted stock awards	15,929		171,341		187,270
Lapsed restrictions and vesting	(105,956	)	(86,850	)	(192,806	)
Forfeitures	—		(3,196	)	(3,196	)
Restricted shares outstanding at December 31, 2001	—		267,334		267,334
Restricted stock awards	10,420		98,820		109,240
Lapsed restrictions and vesting	(10,420	)	(139,759	)	(150,179	)
Forfeitures	—		(23,349	)	(23,349	)
Restricted shares outstanding at December 31, 2002	—		203,046		203,046
Restricted stock awards	—		63,090		63,090
Lapsed restrictions and vesting	—		(119,647	)	(119,647	)
Restricted shares outstanding at December 31, 2003	—		146,489		146,489

The weighted average market values at grant date for restricted stock awarded during 2003, 2002 and 2001 are $11.47, $14.52 and $13.87, 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.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Common Stock Repurchase Program

During 2003, the Company repurchased 2.1 million shares of common stock for $24.2 million to complete its previously approved stock repurchase programs. Since the inception of the stock repurchase programs in 1996, the Company repurchased 15 million shares in total at an aggregate cost of $171.0 million, including commissions. In February 2004, the Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock. The Company may make purchases of its stock 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 option plans, or may be retired.

Reconciliation of Basic and Diluted Earnings Per Share

The reconciliation of basic and diluted earnings per share before cumulative effect of accounting change is presented below:

	Year Ended December 31, 2003
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change	$	20,616	48,424,212	$	0.42
Effect of dilutive securities:
Unvested restricted stock		—	51,809
Stock options		—	338,740
Diluted earnings per share:
Income before cumulative effect of accounting change	$	20,616	48,814,761	$	0.42

	Year Ended December 31, 2002
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change	$	28,967	49,862,417	$	0.58
Effect of dilutive securities:
Unvested restricted stock		—	77,890
Stock options		—	440,161
Diluted earnings per share:
Income before cumulative effect of accounting change	$	28,967	50,380,468	$	0.57

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31, 2001
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change	$	63,659	50,821,140	$	1.25
Effect of dilutive securities:
Unvested restricted stock		—	66,426
Stock options		—	834,785
Diluted earnings per share:
Income before cumulative effect of accounting change	$	63,659	51,722,351	$	1.23

Options excluded from the computation of diluted earnings per share because the exercise price was greater than the average market price for the periods presented are as follows:

	Years Ended December 31,
	2003		2002		2001
Options excluded		1,029,411		633,588		177,372
Exercise price range	$	11.00 - $15.99	$	11.19 - $15.99	$	12.60 - $15.99

F. Accumulated Other Comprehensive Income (Loss)

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

	Net Unrealized Gains (Losses) on Marketable Securities			Minimum Pension Liability Adjustments			Accumulated Other Comprehensive Income (Loss)
Balance at December 31, 2000	$	2,902		$	—		$	2,902
Other comprehensive loss		(2,522	)		(824	)		(3,346	)
Income tax benefit		883			313			1,196
Balance at December 31, 2001		1,263			(511	)		752
Other comprehensive loss		(3,412	)		(21,148	)		(24,560	)
Income tax benefit		1,194			8,193			9,387
Balance at December 31, 2002		(955	)		(13,466	)		(14,421	)
Other comprehensive income (loss)		9,486			(4,234	)		5,252
Income tax (expense) benefit		(2,117	)		1,673			(444	)
Balance at December 31, 2003	$	6,414		$	(16,027	)	$	(9,613	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

G. Long-Term Debt and Financing Obligations

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

	December 31,
	2003			2002
	(In thousands)
Long-Term Debt:
First Mortgage Bonds (1):
8.25% Series C, issued 1996, due 2003	$	—		$	39,360
8.90% Series D, issued 1996, due 2006		186,182			186,182
9.40% Series E, issued 1996, due 2011		209,184			209,184
Pollution Control Bonds (2):
6.375% 1994 Series A bonds, due 2014		63,500			63,500
6.375% 1985 Series A refunding bonds, due 2015		59,235			59,235
6.250% 2002 Series A refunding bonds, due 2037		37,100			37,100
6.375% 2002 Series A refunding bonds, due 2032		33,300			33,300
Promissory note, due 2005 ($116 due in 2004) (3)		151			259
Total long-term debt		588,652			628,120
Financing Obligations:
Nuclear fuel ($21,990 due in 2004) (4)		42,176			47,216
Total long-term debt and financing obligations		630,828			675,336
Current Maturities (amount due within one year)		(22,106	)		(60,961	)
	$	608,722		$	614,375

⁽¹⁾ First Mortgage Bonds

Substantially all of the Company’s utility plant is subject to liens under the First Mortgage Indenture. The First Mortgage Indenture imposes certain limitations on the ability of the Company to (i) declare or pay dividends on common stock; (ii) incur additional indebtedness or liens on mortgaged property and (iii) enter into a consolidation, merger or sale of assets.

The Series D bonds may not be redeemed by the Company prior to maturity. The Series E bonds may be redeemed at the option of the Company, in whole or in part, at 104.70% of par value beginning February 1, 2006, 102.35% of par value beginning February 1, 2007, and at par value beginning February 1, 2008. The Company is not required to make mandatory redemption or sinking fund payments with respect to the bonds prior to maturity. The Series C bonds were repaid at maturity in 2003.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Repurchases, excluding repayment upon maturity, of First Mortgage Bonds made during 2003, 2002 and 2001 are as follows (in thousands):

	Years Ended December 31,
	2003		2002		2001
8.25% Series C	$	3,278	$	3,553	$	41,592
8.90% Series D		—		20,500		370
9.40% Series E		—		9,150		11,666
Total	$	3,278	$	33,203	$	53,628

Internally generated funds were used for the above repurchases. Losses of $3.4 million and $3.6 million were recorded in 2002 and 2001, respectively, relating to these repurchases and include premiums paid and unamortized issuance costs.

⁽²⁾ Pollution Control Bonds

The Company has four series of tax exempt Pollution Control Bonds in an aggregate principal amount of approximately $193.1 million. Upon the occurrence of certain events, which includes the remarketing of the bonds, the bonds may be required to be repurchased at the holder’s option or are subject to mandatory redemption. All of the pollution control bonds interest rates remain at their current fixed interest rates until remarketing in August 2005.

⁽³⁾ Promissory Note

The note has an annual interest rate of 5.5% and is secured by certain furniture and fixtures.

⁽⁴⁾ Nuclear Fuel Financing

The Company has available a $100 million credit facility that was renewed for a three-year term in January 2002. The credit facility provides for up to $70 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 and has secured this obligation with Collateral Series First Mortgage Bonds. 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 may be borrowed by the Company for working capital needs.

The $100 million credit facility requires compliance with certain total debt and interest coverage ratios. The Company was in compliance with these requirements throughout 2003. No amounts are currently outstanding on this facility for working capital needs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2003, the scheduled maturities for the next five years of long-term debt and financing obligations are as follows (in thousands):

2004	$	116
2005		193,170
2006		186,182
2007		—
2008		—

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

H. Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2003 and 2002 are presented below (in thousands):

	December 31,
	2003			2002
Deferred tax assets:
Benefits of federal tax loss carryforwards	$	26,650		$	26,398
Pensions and benefits		55,140			53,453
Asset retirement obligation		19,302			51,055
Alternative minimum tax credit carryforward		37,073			34,981
Investment tax credit carryforward		4,570			5,725
Reorganization expenses financed with bonds		—			2,606
Other		7,186			15,650
Total gross deferred tax assets		149,921			189,868
Less federal valuation allowance		2,284			3,069
Net deferred tax assets		147,637			186,799
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences		(215,056	)		(229,375	)
Decommissioning		(24,077	)		(14,111	)
Other		(11,861	)		(12,248	)
Total gross deferred tax liabilities		(250,994	)		(255,734	)
Net accumulated deferred income taxes	$	(103,357	)	$	(68,935	)

The deferred tax asset valuation allowance decreased by approximately $0.8 million, $6.8 million and $17.7 million in 2003, 2002 and 2001, respectively. The 2003 valuation allowance decrease of $0.8 million consists of (i) a $0.3 million adjustment to capital in excess of stated value in accordance with Statement of Position (“SOP”) 90-7, “Financial Reporting by Entities in Reorganization Under Bankruptcy Code” to recognize a tax benefit for valuation allowance that was not used as a result of

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investment tax credits that were utilized in 2003 and (ii) a $0.5 million writedown related to expired investment tax credits of $0.8 million less deferred tax benefits of $0.3 million. The 2002 valuation allowance decrease of $6.8 million consists of (i) a $4.5 million writedown related to expired investment tax credits of $6.9 million less deferred tax benefits of $2.4 million and (ii) a $2.3 million adjustment to capital in excess of stated value in accordance with SOP 90-7 to recognize a tax benefit for a valuation allowance that was not used as a result of investment tax credits that were utilized in 2002. The 2001 valuation allowance decrease of $17.7 million consists of (i) a $2.8 million writedown related to expired investment tax credits of $4.3 million less deferred tax benefits of $1.5 million; (ii) an $8.7 million writedown related to the expiration of state net operating loss (“NOL”) carryforwards at the end of 2001 and (iii) a $6.2 million adjustment of state valuation allowance, which netted with associated federal tax benefits of $2.2 million resulted in a credit to capital in excess of stated value of $4.0 million to recognize a tax benefit for valuation allowance that was not used.

Based on the average annual book income before taxes for the prior three years, excluding the effects of the cumulative effect of accounting change and future projected annual book income, the Company believes that the net deferred tax assets will be fully realized at current levels of book and taxable income. The Company’s valuation allowance of $2.3 million at December 31, 2003, if subsequently recognized as a tax benefit, would be credited directly to capital in excess of stated value in accordance with SOP 90-7.

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

	Years Ended December 31,
	2003			2002			2001
Income tax expense:
Federal:
Current	$	1,873		$	9,668		$	3,354
Deferred		30,699			6,482			26,902
Total federal income tax		32,572			16,150			30,256
State:
Current		1,297			4,508			—
Deferred		4,581			(3,967	)		4,753
Total state income tax		5,878			541			4,753
Total income tax expense		38,450			16,691			35,009
Tax benefit classified as cumulative effect of accounting change		(25,031	)		—			—
Total income tax expense before cumulative effect of accounting change	$	13,419		$	16,691		$	35,009

The current federal income tax expense for 2003, 2002 and 2001 results primarily from the accrual of alternative minimum tax (“AMT”). Deferred federal income tax includes an offsetting AMT

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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benefit of $2.1 million, $13.0 million and $3.1 million for 2003, 2002 and 2001, respectively. The current state income tax expense for 2003 and 2002 results from the expiration of state NOL carryforwards at the end of 2001.

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

	Years Ended December 31,
	2003			2002			2001
Federal income tax expense computed on income at statutory rate	$	34,545		$	15,980		$	34,534
Difference due to:
Reduction in estimated contingent tax liability		—			—			(2,596	)
State taxes, net of federal benefit		3,820			352			3,089
Other		85			359			(18	)
Total income tax expense		38,450			16,691			35,009
Tax benefit classified as cumulative effect of accounting change		(25,031	)		—			—
Total income tax expense before cumulative effect of accounting change	$	13,419		$	16,691		$	35,009
Effective income tax rate		39.0	%		36.6	%		35.5	%

As of December 31, 2003, the Company had $76.1 million of federal tax NOL carryforwards, $4.6 million of investment tax credit (“ITC”) including $0.1 million of wind energy credits and $37.0 million of AMT credit carryforwards. If unused, the NOL carryforwards would expire at the end of 2011, the ITC carryforwards would expire in 2005, and the wind energy tax credits would expire in 2016 through 2018. The AMT credit carryforwards have an unlimited life. The Company recorded a writedown of its expired state NOL carryforwards at the end of 2001. These tax attributes are subject to change should the tentative IRS settlement for tax years 1996 through 1998 be approved by the IRS. In 2001, the Company recorded a $2.6 million adjustment to reduce its estimated contingent tax liabilities based upon discussions and agreed issues with taxing authorities. This $2.6 million adjustment was included as a component of deferred income tax expense. See Note I for further discussion of the IRS examination.

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I. Commitments, Contingencies and Uncertainties

Power Contracts

As of December 31, 2003, 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
Sale off-peak	50 MW	2004
Purchase on-peak	103 MW	2004 through 2005

The Company also has an agreement with a counterparty for power exchanges under which the Company will receive 30 MW of on-peak capacity and associated energy through 2005 at the Eddy County tie and concurrently deliver the same amount at Palo Verde and/or Four Corners. The agreement also gives the counterparty the option to deliver up to 133 MW of off-peak capacity and associated energy through 2005 at the Eddy County tie and concurrently receive the same amount at Palo Verde and/or Four Corners. The Company will receive a guaranteed margin on any energy exchanged under the off-peak agreement.

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 the regulatory agencies. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.

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 $0.9 million as of December 31, 2003, which is related to compliance with federal and state environmental standards. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.

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The following are expenditures incurred by the Company in 2003, 2002 and 2001 for complying with federal environmental statutes (in thousands):

	2003		2002		2001
Clean Air Act	$	1,060	$	739	$	745
Federal Clean Water Act		649		1,930		794

The Company is not aware of any active investigation of its compliance with the environmental requirements by the Environmental Protection Agency, the Texas Commission on Environmental Quality, or the New Mexico Environment Department. Furthermore, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as the Superfund law.

Tax Matters

The IRS has disputed whether the Company was entitled to deduct certain payments made in 1996 related to Palo Verde and its treatment of a litigation settlement in 1997 related to a terminated merger agreement. The Company has reached a tentative agreement, subject to IRS final approval, to settle these and all other issues relative to its 1996 through 1998 federal income tax returns. The Company expects the IRS will make a final decision regarding the proposed settlement by mid 2004. Should the proposed settlement be rejected by the IRS, the Company cannot predict the eventual outcome of this matter. However, the Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome cannot be predicted with certainty, and while the contingent tax reserve may not in fact be sufficient, the Company believes that the amount at December 31, 2003 is a reasonable estimate of any additional tax that may be due.

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 marketing activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. Management of MiraSol continues to assess projects for potential warranty obligations. As part of the assessment, several discussions have been held with a large customer on a $5.6 million generator project. Two warranty issues associated with the project have been identified, and management has contracted with a third party to address the warranty claims. During the year ended December 31, 2002, the Company expensed $2.0 million and created a reserve related to these warranty claims and reduced this liability by approximately $0.6 million related to payments for this item. During the year ended December 31, 2003, the Company had reduced this liability by approximately $0.4 million for payments made related to these matters. Based on a probability analysis performed by the Company, an additional $0.5 million in potential

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

warranty claims were identified and expensed during 2003. As of December 31, 2003, a reserve for those warranty claims in the amount of $1.5 million remains. 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 this customer or any other 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.

Customer Information System

During the third quarter of 2003 the Company completed an assessment of the Customer Information System (“CIS”) project and of alternatives to completion of the project. This assessment included analyzing the impact that potential delays in the implementation of deregulation and resulting changes in billing requirements, and the software’s ability to perform to specification. Based on this assessment and on events related to the project which occurred, the Company abandoned the CIS project and recognized an asset impairment loss of approximately $17.6 million. The Company is now analyzing various options to meet its current and projected CIS needs.

Lease Agreements

The Company has an operating lease for administrative offices. The lease has a 10-year term ending May 31, 2007. The minimum lease payments are $1.0 million annually and are adjusted each year by 50% of the percentage change of the Consumer Price Index. The lease agreement does 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.

As of December 31, 2003, the Company’s minimum future rental payments for the next five years are as follows (in thousands):

2004	$	1,000
2005		1,000
2006		1,000
2007		400
2008		—

Union Matters

On October 2 and 3, 2003, employees in the Company’s meter reading and collections areas, comprised of 68 employees, voted in favor of representation by the International Brotherhood of Electrical Workers, Local 960 (“Local 960”). This vote was certified by the National Labor Relations Board (“NLRB”) on October 14, 2003. In addition, employees in the Company’s facilities services area, comprised of seven employees, voted in favor of representation by Local 960 on October 16, 2003. This vote was certified by the NLRB on October 24, 2003. The Company has begun collective bargaining negotiations with Local 960 on behalf of these employees.

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J. Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that, except as described below, none of these claims will have a material adverse effect on the financial position, results of operations and cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.

On January 16, 2003, the Company was served with a complaint on behalf of a purported class of shareholders alleging violations of the federal securities laws (Roth v. El Paso Electric Company, et al., No. EP-03-CA-0004). The complaint was filed in the El Paso Division of the United States District Court for the Western District of Texas. The suit seeks undisclosed compensatory damages for the class as well as costs and attorneys’ fees. The lead plaintiff, Carpenters Pension Fund of Illinois, filed a consolidated amended complaint on July 2, 2003, alleging, among other things, that the Company and certain of its current and former directors and officers violated securities laws by failing to disclose that some of the Company’s revenues and income were derived from an allegedly unlawful relationship with Enron. The allegations arise out of the FERC investigation of the power markets in the western United States during 2000 and 2001, which the Company previously settled with the FERC Trial Staff and certain intervening parties. See Part I, Item 1, “Regulation – Federal Regulatory Matters.” On August 15, 2003, the Company and the individual defendants filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. On November 26, 2003, the Court denied the motion to dismiss as to the Company and three of the individual defendants and granted the motion to dismiss as to two individual defendants. The lead plaintiff filed its motion for class certification on January 9, 2004, seeking to certify a class consisting of all persons who purchased or otherwise acquired Company securities between February 14, 2000 and October 21, 2002. This matter is presently set for trial on March 28, 2005. The Company is unable to predict the outcome of this case.

On February 10, 2003, the Company received a letter written by a Pennsylvania law firm on behalf of the holder of approximately 200 shares of common stock of the Company (the “shareholder”), that demands that the Company commence a lawsuit against each member of the Board of Directors to recover damages allegedly sustained by the Company as a result of alleged breaches of fiduciary duties by the Board. The shareholder contends that, from 1997 to 2002, the Board knowingly caused or allowed the Company to participate in improper transactions with Enron Corporation and certain of its subsidiaries. The allegations appear to duplicate factual questions first raised by the FERC in an investigation of the power markets in the western United States during 2000 and 2001. As noted above, the Company reached a settlement of the FERC investigation with the FERC Trial Staff and certain intervenors. In accordance with Texas law, the independent and disinterested directors of the Company conducted an independent inquiry and concluded that a lawsuit against the Board is not in the best interests of the Company. To date, the shareholder has not filed a shareholder derivative lawsuit against the members of the Board. The Company is unable to predict the outcome of this matter.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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On May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state anti-trust laws, as well as for breach of contract and fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. On December 4, 2003, the case was transferred to the United States District Court for the Southern District of California for inclusion in the California Wholesale Electricity Antitrust Multi-District Litigation cases pending in that district (re-styled Port of Seattle v. Avista Corporation, et al., No. CV 03-2474-RHW, MDL No. 1403). The Company, together with several other defendants, filed a motion to dismiss on July 29, 2003. The motions to dismiss are scheduled for oral argument on March 26, 2004. While the Company believes the lawsuit is without merit and will defend itself vigorously, it is unable to predict the outcome of this case.

On February 9, 2004, Enron North America Corp. (“ENA”) filed suit against the Company seeking payment of approximately $5.4 million, plus interest and costs, relating to certain natural gas supply contracts (Enron North America Corp. v. El Paso Electric Co., Case No. 01-16034, United States Bankruptcy Court, Southern District of New York). The complaint alleges that ENA entered into two natural gas supply contracts with the Company which automatically terminated as a result of ENA’s bankruptcy. ENA contends that, under the terms of the contracts, the Company owes ENA termination payments because the market price of natural gas at the date of termination was lower than the contract price. While ENA acknowledges that the contracts contain a provision (the “One-Way Payment Provision”) under which the termination payment would be calculated to be zero, ENA seeks a ruling from the court that the One-Way Payment Provision is unenforceable and that the Company should be required to pay termination payments in the amount of approximately $5.4 million, plus interest and costs. The first of these two contracts covers gas to be supplied by ENA during the months of November and December of 2001 (the “2001 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2001 Contract is approximately $1.8 million. The second of these two contracts covers gas to be supplied by ENA during the months of January through December of 2002 (the “2002 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2002 Contract is approximately $3.6 million. Based upon the Company’s assessment of the probability of an adverse outcome, the Company has expensed a pre-tax amount of $1.5 million as of December 31, 2003 for this matter. The Company intends to defend itself vigorously, but cannot predict the outcome of this matter.

On November 3, 2003, TNP filed a complaint against the Company with the FERC, asking the FERC to make a determination that TNP has a rollover right to network-type transmission service over the Company’s transmission system. TNP asserts that it has such rights under the rollover provisions of FERC Order No. 888 relating to its power sale agreement with the Company that expired on

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002. The Company’s position is that the transmission service provided by the Company to TNP under the expired power sale agreement was point-to-point service and not network service and that the Company does not have the capacity to provide the network service that TNP seeks. Due to existing transmission constraints, a FERC ruling granting TNP’s request could adversely impact the Company’s ability to import lower cost power from Palo Verde and Four Corners to serve its base load to the extent of the transmission rights granted to TNP. A hearing on this matter before an administrative law judge is scheduled for June 15, 2004. The Company cannot predict the likely outcome of this matter or the full effect that an adverse ruling would have on the Company.

K. 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 based on the minimum funding amounts required by the Department of Labor and 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’s Non-Qualified Retirement Income Plan is a non-funded defined benefit plan which covers certain former employees of the Company. During 1996, as part of the Company’s reorganization, the Company terminated the Non-Qualified Retirement Income Plan with respect to all active employees. The benefit cost for the Non-Qualified Retirement Income Plan is based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.

The Company uses a measurement date of December 31 for its retirement plans. The Company accounts for the Retirement Plan and the Non-Qualified Retirement Income Plan under SFAS No. 87, “Employers’ Accounting for Pensions.” In accordance with SFAS No. 87, the net periodic benefit cost includes amortization of unrecognized net gains or losses which exceeded 10% of the benefit obligation at the beginning of the year. Unrecognized gains or losses on investment assets of the plans are not amortized. The amortization reflects the excess divided by the average remaining service period of active employees expected to receive benefits.

In 2003, the Company adopted SFAS No. 132 (revised 2003), “Employers’ Disclosure about Pensions and Other Postretirement Benefits,” (“SFAS No. 132 revised”) which expands the original disclosure requirements of SFAS No. 132.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

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The amounts recognized in the Company’s balance sheets and the funded status of the plans at December 31, 2003 and 2002 are presented below (in thousands):

	Years Ended December 31,
	2003						2002
	Retirement Income Plan			Non-Qualified Retirement Income Plan			Retirement Income Plan			Non-Qualified Retirement Income Plan
Change in benefit obligation:
Benefit obligation at beginning of year	$	(130,754	)	$	(19,185	)	$	(114,166	)	$	(18,434	)
Service cost		(3,812	)		—			(3,359	)		—
Interest cost		(8,403	)		(1,207	)		(7,867	)		(1,257	)
Actuarial loss (1)		(11,513	)		(1,074	)		(9,168	)		(1,146	)
Benefits paid		4,304			1,650			4,045			1,652
Plan amendments (2)		—			—			(239	)		—
Benefit obligation at end of year		(150,178	)		(19,816	)		(130,754	)		(19,185	)
Change in fair value of plan assets:
Fair value of plan assets at beginning of year		72,466			—			81,559			—
Actual gain/(loss) on plan assets		11,106			—			(9,112	)		—
Employer contribution		8,290			1,650			4,064			1,652
Benefits paid		(4,304	)		(1,650	)		(4,045	)		(1,652	)
Fair value of plan assets at end of year		87,558			—			72,466			—
Funded status		(62,620	)		(19,816	)		(58,288	)		(19,185	)
Unrecognized net loss		52,613			3,029			46,389			1,970
Intangible asset		196			—			218			—
Balance of additional liability (3)		(23,373	)		(3,029	)		(20,220	)		(1,970	)
Accrued benefit liability	$	(33,184	)	$	(19,816	)	$	(31,901	)	$	(19,185	)

⁽¹⁾ Represents a decrease in the discount rate.

⁽²⁾ Represents changes in accordance with the Economic Growth and Tax Relief Reconciliation Act of 2001.

⁽³⁾ As necessary, an additional liability is included in the accrued benefit liability if the accumulated benefit obligation exceeds the fair value of plan assets. The accumulated benefit obligation is an alternative measure of the retirement plans obligations. It is calculated similar to the above benefit obligation, except that current or past compensation levels, instead of future compensation levels, are used to determine retirement plans benefits. The additional liability is calculated at the end of each fiscal year and any change in it is recorded as a component of other comprehensive income (loss). Other comprehensive income (loss) includes ($4,234) and ($21,148) for 2003 and 2002, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Weighted average actuarial assumptions used in determining the actuarial present value of the benefit obligations are as follows:

	2003				2002
	Retirement Income Plan		Non-Qualified Retirement Income Plan		Retirement Income Plan		Non-Qualified Retirement Income Plan
Discount rate	6.00	%	6.00	%	6.50	%	6.50	%
Expected return on plan assets	8.50	%	N/A		8.50	%	N/A
Rate of compensation increase	5.00	%	N/A		5.00	%	N/A

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

	2003						2002
	Retirement Income Plan			Non-Qualified Retirement Income Plan			Retirement Income Plan			Non-Qualified Retirement Income Plan
Prepaid benefit cost	$	—		$	—		$	—		$	—
Accrued benefit cost		(9,811	)		(16,787	)		(11,681	)		(17,215	)
Balance of additional liability		(23,373	)		(3,029	)		(20,220	)		(1,970	)
Intangible assets		196			—			218			—
Accumulated other comprehensive income		23,177			3,029			20,002			1,970
Net amount recognized	$	(9,811	)	$	(16,787	)	$	(11,681	)	$	(17,215	)

The accumulated benefit obligation for the retirement plans was $140.6 million and $123.6 million at December 31, 2003 and 2002, respectively.

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

	2003						2002
	Retirement Income Plan			Non-Qualified Retirement Income Plan			Retirement Income Plan			Non-Qualified Retirement Income Plan
Projected benefit obligation	$	(150,178	)	$	(19,816	)	$	(130,754	)	$	(19,185	)
Accumulated benefit obligation		(120,742	)		(19,816	)		(104,367	)		(19,185	)
Fair value of plan assets		87,558			—			72,466			—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net periodic benefit cost is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):

	Years Ended December 31,
	2003			2002			2001
Components of net periodic benefit cost:
Service cost	$	3,812		$	3,359		$	3,085
Interest cost		9,610			9,124			8,641
Expected return on plan assets		(7,536	)		(7,761	)		(7,673	)
Amortization of:
Unrecognized gain		1,736			—			—
Unrecognized prior service cost		21			21			—
Net periodic benefit cost	$	7,643		$	4,743		$	4,053

Weighted average actuarial assumptions used in determining the net periodic benefit costs are as follows:

	2003		2002		2001
Discount rate	6.50	%	7.00	%	7.25	%
Expected return on plan assets	8.50	%	8.50	%	8.50	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%

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 sum of the expected returns on individual asset categories with a target asset allocation of 65% equity and 35% debt securities. The expected returns for equity securities are based on historical risk premiums above the current fixed income rate, while the expected returns for the debt securities are based on the portfolio’s yield to maturity.

Given recent market conditions, the Company has emphasized capital preservation and therefore, the asset allocations at December 31, 2003 and 2002 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s Retirement Plan weighted-average asset allocations at December 31, 2003 and 2002, by asset category are as follows:

	December 31,
	2003		2002
Asset Category:
Equity securities	41	%	44	%
Debt securities	35		46
Cash equivalents	24		10
Total	100	%	100	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s investment goals for the Retirement Plan are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in equity and debt securities, mutual funds and cash/cash equivalents and prohibit direct investments in fixed income derivatives, foreign debt securities, real estate or commingled funds, private placements and tax-exempt debt of state and local governments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international equity securities and domestic fixed income securities. The liquidity of these funds is enhanced through the purchase of highly marketable securities.

The Company expects to contribute $7.6 million to its retirement plans in 2004. Contributions for the Retirement Plan are based on the minimum funding amounts required by the Department of Labor and IRS as actuarially calculated.

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. Those benefits are accounted for under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” In accordance with SFAS No. 106, the 2003, 2002 and 2001 net periodic benefit cost includes amortization of unrecognized net gains or losses which exceeded 10% of the benefit obligation at the beginning of the year in which they occurred. The amortization reflects the excess divided by the average remaining service period of active employees expected to receive benefits. Unrecognized gains or losses on investment assets of the plans are not amortized. Contributions from the Company are based on the funding amounts required by the Texas Commission in the Texas Rate Stipulation. 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 uses a measurement date of December 31 for its other postretirement benefits plan.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the “Act”) became law in the United States. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. In accordance with FASB Staff Position FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” the Company has elected to defer recognition of the effects of the Act in any measures of the benefit obligation or cost. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information. Currently, the Company cannot predict whether it will need to amend its plan to benefit from the Act. In 2003, the Company adopted SFAS No. 132 revised, which expands the disclosure requirements of SFAS No. 132.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The amounts recognized in the Company’s balance sheets and the funded status of the plan at December 31, 2003 and 2002 are presented below (in thousands):

	December 31,
	2003			2002
Change in benefit obligation:
Benefit obligation at beginning of year	$	(96,561	)	$	(88,506	)
Service cost		(3,915	)		(3,118	)
Interest cost		(6,468	)		(5,692	)
Actuarial loss (1)		(13,525	)		(1,093	)
Retirees’ contributions		(310	)		(297	)
Benefits paid		2,597			2,145
Benefit obligation at end of year		(118,182	)		(96,561	)
Change in fair value of plan assets:
Fair value of plan assets at beginning of year		16,716			16,233
Actual gain (loss) on plan assets		3,055			(1,091	)
Employer contribution		3,422			3,422
Retirees’ contributions		310			297
Benefits paid		(2,597	)		(2,145	)
Fair value of plan assets at end of year		20,906			16,716
Funded status		(97,276	)		(79,845	)
Unrecognized net (gain) loss		2,766			(8,724	)
Accrued benefit liability	$	(94,510	)	$	(88,569	)

⁽¹⁾ Represents a decrease in the discount rate.

Amounts recognized in the Company’s balance sheet consist of accrued postretirement costs of $94.5 million and $88.6 million for 2003 and 2002, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

	Years Ended December 31,
	2003			2002			2001
Components of net periodic benefit cost:
Service cost	$	3,915		$	3,118		$	3,170
Interest cost		6,468			5,692			5,548
Expected return on plan assets		(1,020	)		(999	)		(942	)
Amortization of unrecognized gain		—			(794	)		(1,164	)
Net periodic benefit cost	$	9,363		$	7,017		$	6,612

Weighted average assumptions are as follows:

	2003		2002		2001
Discount rate	6.00	%	6.50	%	7.00	%
Expected return on plan assets, after-tax	5.90	%	5.90	%	5.90	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%

For measurement purposes, a 9.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2004; the rate was assumed to decrease gradually to 6% for 2006 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 $20.1 million or $15.9 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of net periodic benefit cost by $1.9 million or $1.5 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.90%. This return is based on the sum of the expected returns on individual asset categories with a target asset allocation of 60% equity and 40% debt securities. The expected returns for equity securities are based on historical risk premiums above the current fixed income rate, while the expected returns for the debt securities are based on the portfolio’s yield to maturity.

Given recent market conditions, the Company has emphasized capital preservation and therefore, the asset allocations at December 31, 2003 and 2002 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s other postretirement benefits plan weighted average asset allocations at December 31, 2003 and 2002, by asset category are as follows:

	December 31,
	2003		2002
Asset Category:
Equity securities	54	%	55	%
Debt securities	33		36
Cash equivalents	13		9
Total	100	%	100	%

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company’s investment goals for the postretirement benefits plan are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in equity and debt securities, mutual funds and cash/cash equivalents and prohibit direct investments in fixed income derivatives, foreign debt securities, real estate or commingled funds and private placements. The Company’s investment policies and strategies for the postretirement benefits plan are based on target allocations for individual asset categories. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international equity securities and domestic fixed income securities. The liquidity of these funds is enhanced through the purchase of highly marketable securities.

The Company expects to contribute $3.4 million to its other postretirement benefits plan in 2004.

All Employee Cash Bonus Plan

The All Employee Cash Bonus Plan (the “Bonus Plan”), was established to reward employees for their contribution in helping the Company attain its corporate goals. Eligible employees below manager level would receive a cash bonus if the Company attained established levels of safety, customer satisfaction and financial results during 2003. The Company was able to attain the required minimum levels of improvement in safety performance measures for 2003 and 2002 and quarterly safety bonuses totaling $0.7 million and $1.0 million, respectively, were expensed. However, the financial goal had to be met before any bonus amounts would be paid relating to customer satisfaction and financial results. The Company was unable to attain the required minimum level of improvement for the financial goal for 2003 and 2002. As a result, the Company did not pay a cash bonus relating to customer satisfaction and financial results for 2003 and 2002. The Company expensed in 2001 approximately $3.7 million in cash bonuses. The Company has renewed the Bonus Plan in 2004 with similar goals.

L. Franchises and Significant Customers

City of El Paso Franchise

The Company’s major franchise is with the City of El Paso, Texas (“City”). The franchise agreement includes a 2% annual franchise fee (approximately $7.7 million per year currently) and provides an arrangement for the Company’s utilization of public rights-of-way necessary to serve its retail customers within the City. The franchise with the City extends through August 1, 2005.

In a provision of the franchise agreement, the City has an option to acquire all of the non-cash assets of the Company at the end of the term of the franchise on August 1, 2005, at a purchase price equal to the fair market value of the assets (measured on a cost of reproduction basis) on the date one year prior to the end of the term. The purchase price is then subject to certain adjustments to roll the

84

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

value of the assets forward to the end of the term. If the City wishes to exercise its option, it must deliver written notice to the Company one year prior to the expiration of the franchise term.

Las Cruces Franchise

In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.1 million per year currently) for the provision of electric distribution service. Las Cruces is prohibited during this seven-year period from taking any action to condemn or otherwise attempt to acquire the Company’s distribution system, or attempt to operate or build its own electric distribution system. Las Cruces will have a 90-day non-assignable option at the end of the Company’s seven-year franchise agreement to purchase the portion of the Company’s distribution system that serves Las Cruces at a purchase price of 130% of the Company’s book value at that time. If Las Cruces exercises this option, it is prohibited from reselling the distribution assets for two years. If Las Cruces fails to exercise this option, the franchise and standstill agreements will be extended for an additional two years.

Military Installations

The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company currently has long-term contracts with all three military bases that it serves. The Company signed a contract with Ft. Bliss in December 1998, under which Ft. Bliss will take service from the Company through December 2008. The Company has a contract to provide retail electric service to Holloman for a ten-year term which began in December 1995. In May 1999, the Army and the Company entered into a new ten-year contract to provide retail electric service to White Sands.

M. 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, 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. Decommissioning trust funds are carried at market value.

85

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 at December 31, 2003 and 2002 and are presented below (in thousands):

	2003				2002
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
First Mortgage Bonds	$	395,366	$	447,662	$	434,726	$	451,800
Pollution Control Bonds		193,135		201,700		193,135		194,667
Nuclear Fuel Financing (1)		42,176		42,176		47,216		47,216
Total	$	630,677	$	691,538	$	675,077	$	693,683

⁽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.

As of January 1, 2001, the Company adopted 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 Financial Accounting Standards Board’s (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.

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, 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, 2003, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.

The fair value of the Company’s marketable securities at December 31, 2003 was $80.5 million. Gross unrealized losses on marketable securities and the fair value of the related securities, aggregated

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2003, were as follows:

	Less than 12 Months					12 Months or Longer					Total
	Fair Value		Unrealized Losses			Fair Value		Unrealized Losses			Fair Value		Unrealized Losses
Description of Securities:
U.S. Treasury Obligations and Direct Obligations of U.S. Government Agencies	$	344	$	(8	)	$	497	$	(41	)	$	841	$	(49	)
Federal Agency Mortgage Backed Securities		782		(9	)		—		—			782		(9	)
Municipal Obligations		2,710		(29	)		642		(23	)		3,352		(52	)
Corporate Obligations		1,221		(26	)		—		—			1,221		(26	)
Total debt securities		5,057		(72	)		1,139		(64	)		6,196		(136	)
Common stock		4,960		(244	)		3,248		(810	)		8,208		(1,054	)
Total temporarily impaired securities	$	10,017	$	(316	)	$	4,387	$	(874	)	$	14,404	$	(1,190	)

The total impaired securities are comprised of approximately fifty investments that are in an unrealized loss position. The Company monitors the length of time the investment 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 determined 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 investments until their market price recovers, these investments are not considered other-than-temporarily impaired. During the years ended December 31, 2003, 2002 and 2001, the Company recognized other than temporary impairment losses of marketable securities of $0.6 million, $2.7 million and $1.8 million, respectively.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

N. Supplemental Statements of Cash Flows Disclosures

	Years Ended December 31,
	2003		2002		2001
	(In thousands)
Cash paid for:
Interest on long-term debt and financing obligations	$	51,596	$	55,785	$	61,067
Income taxes		17,660		15,133		3,550
Other interest		12		16		23
Non-cash investing and financing activities:
Grants of restricted shares of common stock		724		1,586		2,597
Remeasurements of options		—		240		430
Change in estimate of decommissioning liability capitalized to electric plant in service		—		—		1,795
Change in federal and state deferred tax valuation allowance credited to capital in excess of stated value (1)		295		2,308		4,046
Plant in service acquired through incurring obligation subject to a service agreement		8,139		—		—

⁽¹⁾ See Note H.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

O. Selected Quarterly Financial Data (Unaudited)

	2003 Quarters								2002 Quarters
	4th		3rd		2nd		1st		4th			3rd		2nd		1st
	(In thousands except for share data)
Operating revenues (1)	$	156,953	$	197,425	$	162,498	$	147,486	$	153,798		$	206,068	$	181,022	$	149,197
Operating income (loss)		16,786		28,600		19,295		15,534		(95	)		48,187		35,448		27,067
Income (loss) before cumulative effect of accounting change		2,259		11,246		4,995		2,116		(8,705	)		19,503		12,318		5,851
Cumulative effect of accounting change, net of tax		—		—		—		39,635		—			—		—		—
Net income (loss)		2,259		11,246		4,995		41,751		(8,705	)		19,503		12,318		5,851
Basic earnings per share:
Income (loss) before cumulative effect of accounting change		0.05		0.23		0.10		0.04		(0.18	)		0.39		0.25		0.12
Cumulative effect of accounting change, net of tax		—		—		—		0.81		—			—		—		—
Net income (loss)		0.05		0.23		0.10		0.85		(0.18	)		0.39		0.25		0.12
Diluted earnings per share:
Income (loss) before cumulative effect of accounting change		0.05		0.23		0.10		0.04		(0.18	)		0.39		0.24		0.12
Cumulative effect of accounting change, net of tax		—		—		—		0.80		—			—		—		—
Net income (loss)		0.05		0.23		0.10		0.84		(0.18	)		0.39		0.24		0.12

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

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

Not applicable.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures. The Company’s chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2003, (the “Evaluation Date”), have concluded that as of the Evaluation Date, the Company’s disclosure controls and procedures (as required by paragraph (b) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15) were adequate and designed to ensure that material information relating to the Company and the Company’s consolidated subsidiary would be made known to them by others within those entities.

Changes in internal control over financial reporting. There were no changes in the Company’s 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, 2003, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

Item 10. Directors and Executive Officers of the Registrant

Information regarding directors is incorporated herein by reference from the Company’s definitive proxy statement for the 2004 Annual Meeting of Shareholders (the “2004 Proxy Statement”). Information regarding executive officers of the Company, included herein under the caption “Executive Officers of the Registrant” in Part I, Item 1 above, is incorporated herein by reference.

Item 11. Executive Compensation

Incorporated herein by reference from the 2004 Proxy Statement.

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Item 12. Security Ownership of Certain Beneficial Owners and Management

Incorporated herein by reference from the 2004 Proxy Statement.

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	2,171,454	$	10.36	694,775
Equity compensation plans not approved by security holders	—		—	—
Total	2,171,454	$	10.36	694,775

Item 13. Certain Relationships and Related Transactions

Incorporated herein by reference from the 2004 Proxy Statement.

Item 14. Principal Accounting Fees and Services

Incorporated herein by reference from the 2004 Proxy Statement.

PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

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

		Page
1.	Financial Statements:
	See Index to Financial Statements	38
2.	Financial Statement Schedules:
	All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.
3.	Exhibits

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

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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)
3.01-01	–	Statement of Resolution Establishing Series of Preferred Stock, dated February 7, 1996 and effective February 12, 1996, amending Exhibit 3.01. (Exhibit 3.01-01 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)
4.02	–	Reserved
4.03	–	Indenture of Trust, dated as of July 1, 1994, between Maricopa County, Arizona Pollution Control Corporation and Texas Commerce Bank National Association, as Trustee, related to $63,500,000 principal amount of Maricopa County, Arizona Pollution Control Corporation Adjustable Tender Pollution Control Revenue Bonds, 1994 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.03-01	–	Supplemental Indenture of Trust No. 1, dated as of December 12, 1995, related to Exhibit 4.03, including form of bond. (Exhibit 4.03-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.04	–	Loan Agreement, dated as of July 1, 1994, between Maricopa County, Arizona Pollution Control Corporation and the Company, related to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.04-01	–	Supplemental Loan Agreement No. 1, dated as of February 12, 1996, related to

92

		Exhibit 4.04. (Exhibit 4.04-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.05	–	Remarketing Agreement, dated as of July 1, 1994, between the Company and Smith Barney Inc., related to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.05-01	–	Amendment Agreement, dated August 16, 2000, to Exhibits 4.05, 4.11 and 4.21. (Exhibit 4.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)
4.06	–	Tender Agreement, dated as of July 1, 1994, between the Company and Smith Barney Inc., related to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.07	–	Ordinance No. 94-1018 adopted by the City Council of the City of Farmington, New Mexico, on October 18, 1994, authorizing and providing for the issuance by the City of Farmington, New Mexico, of $33,300,000 principal amount of its Adjustable Tender Pollution Control Revenue Refunding Bonds, 1994 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.07-01	–	Ordinance No. 96-1035 adopted by the City Council of the City of Farmington, New Mexico, on January 23, 1996 as Supplemental Ordinance No. 1, related to Exhibit 4.07. (Exhibit 4.07-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.08	–	Resolution No. 94-798 adopted by the City Council of the City of Farmington, New Mexico, on October 18, 1994, relating to the issuance of the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.09	–	Amended and Restated Installment Sale Agreement, dated as of November 1, 1994, between the Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.10	–	Representation and Indemnity Agreement, dated as of October 31, 1994, between the Company, the City of Farmington, New Mexico, and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.10 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.11	–	Remarketing Agreement, dated as of November 1, 1994, between the Company and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.11 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)

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4.12	–	Tender Agreement, dated as of November 1, 1994, between the Company and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.12 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.13	–	Reserved
4.14	–	Loan Agreement, dated as of December 1, 1984, between Maricopa County, Arizona Pollution Control Corporation and the Company, relating to $37,100,000 principal amount of Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds, 1984 Series E (El Paso Electric Company Palo Verde Project). (Exhibit 4.27 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.14-01	–	Supplemental Loan Agreement, dated as of June 1, 1986, to Exhibit 4.14. (Exhibit 4.29-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
4.14-02	–	Supplemental Loan Agreement No. 3, dated as of February 12, 1996, to Exhibit 4.14. (Exhibit 4.14-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.15	–	Trust Indenture, dated as of December 1, 1984, by and between Maricopa County, Arizona Pollution Control Corporation and MBank El Paso, National Association, as Trustee, securing the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.27-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.15-01	–	Supplemental Trust Indenture No. 2, dated as of June 1, 1986, to Exhibit 4.15. (Exhibit 4.29-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
4.15-02	–	Supplemental Trust Indenture No. 3, dated as of May 6, 1994, to Exhibit 4.15. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1994)
4.15-03	–	Supplemental Trust Indenture No. 4, dated as of November 30, 1995, to Exhibit 4.15, including form of bond. (Exhibit 4.15-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.16	–	Indexing Agent’s Agreement among Maricopa County, Arizona Pollution Control Corporation, the Company and Smith Barney, Harris Upham & Co., Incorporated, relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.27-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.17	–	Remarketing Agent Agreement, dated as of May 6, 1994, between Smith Barney Shearson Inc., and the Company, relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.02 to the Company’s

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		Quarterly Report on Form 10-Q for the quarter ended June 30, 1994)
4.17-01	–	Amendment Agreement, dated August 16, 2000, to Exhibit 4.17. (Exhibit 4.17-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)
4.18	–	Loan Agreement, dated as of February 12, 1996, between Maricopa County, Arizona Pollution Control Corporation and the Company, relating to $59,235,000 principal amount of Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds, 1985 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.19	–	Indenture of Trust, dated as of February 12, 1996, by and between Maricopa County, Arizona Pollution Control Corporation and Texas Commerce Bank National Association, as Trustee, relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.18. (Exhibit 4.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.20	–	Tender Agent Agreement, dated as of February 12, 1996, between the Company and Smith Barney Inc., relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.18. (Exhibit 4.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.21	–	Remarketing Agent Agreement, dated as of February 12, 1996, between the Company and Smith Barney Inc., relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.18. (Exhibit 4.21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.22	–	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)
4.23	–	Tender Agreement dated August 1, 2002, between the Company and Salomon Smith Barney Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.22. (Exhibit 4.23 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.24	–	Remarketing Agreement dated August 1, 2002, between the Company and Salomon Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.22. (Exhibit 4.24 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.25	–	Amended and Restated Installment Sale Agreement dated August 1, 2002, between the Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.22. (Exhibit 4.25 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)

95

4.26	–	Indenture of Trust dated August 1, 2002, between Maricopa County, Arizona Pollution Control Corporation and JPMorgan Chase Bank, as trustee, relating to $37,100,000 principal amount of Maricopa County, Arizona Pollution Control Refunding Revenue Bonds, 2002 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.26 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.27	–	Loan Agreement dated August 1, 2002, between Maricopa County, Arizona Pollution Control Corporation and the Company, relating to the Pollution Control Bonds referred to in Exhibit 4.26. (Exhibit 4.27 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.28	–	Remarketing Agreement dated August 1, 2002, between the Company and Salomon Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.26. (Exhibit 4.28 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
4.29	–	Tender Agreement dated August 1, 2002, between the Company and Salomon Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.26. (Exhibit 4.29 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)
Exhibit 10 – Material Contracts:
10.01	–	Co-Tenancy Agreement, dated July 19, 1966, and Amendments No. 1 through 5 thereto, between the Participants of the Four Corners Project, defining the respective ownerships, rights and obligations of the Parties. (Exhibit 10.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.01-01	–	Amendment No. 6, dated February 3, 2000, to Exhibit 10.01. (Exhibit 10.01-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.02	–	Supplemental and Additional Indenture of Lease, dated May 27, 1966, including amendments and supplements to original Lease Four Corners Units 1, 2 and 3, between the Navajo Tribe of Indians and Arizona Public Service Company, and including new Lease Four Corners Units 4 and 5, between the Navajo Tribe of Indians and Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company. (Exhibit 4-e to Registration Statement No. 2-28692 on Form S-9)
10.02-01	–	Amendment and Supplement No. 1, dated March 21, 1985, to Exhibit 10.02. (Exhibit 19.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1985)
10.03	–	El Paso Electric Company 1996 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-17971 on Form S-8)
10.04	–	Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico,

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		Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.04-01	–	Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)
10.04-02	–	Amendment No. 12, dated February 3, 2000, to Exhibit 10.04. (Exhibit 10.04-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.05	–	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.05-01	–	Amendment No. 14, dated June 20, 2000, to Exhibit 10.05. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.06	–	ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
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	–	Trust Agreement, dated as of May 1, 1980, between The Bank of New York, as Beneficiary, and First Security Bank of Utah, N.A., and Robert S. Clark, as Owner Trustees, establishing a trust designated as El Paso Electric Company (1980) Equipment Trust No. 2. (Exhibit 5-p-1 to Registration Statement No. 2-68414 on Form S-7)
10.10	–	Trust Indenture, dated as of May 1, 1980, between The Connecticut Bank and Trust Company, as Indenture Trustee, and First Security Bank of Utah, N.A., and

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		Robert S. Clark, Owner Trustees. (Exhibit 5-p-2 to Registration Statement No. 2-68414 on Form S-7)
10.11	–	Reserved
10.12	–	Participation Agreement, dated as of May 1, 1980, among the Company, as Lessee, The Bank of New York, as Beneficiary, First Security Bank of Utah, N.A., and Robert S. Clark, as Owner Trustees, The Connecticut Bank and Trust Company, as Indenture Trustee, Franklin Life Insurance Company, Woodmen of the World Life Insurance Society, Minnesota Mutual Life Insurance Company, MacCabees Mutual Life Insurance Company and Mutual Service Insurance Company, as Lenders, pertaining to Exhibit 10.11. (Exhibit 5-p-4 to Registration Statement No. 2-68414 on Form S-7)
10.13	–	Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.13-01	–	Letter Agreement, dated December 19, 1996, modifying Service Schedule E, relating to Exhibit 10.13. (Exhibit 10.13-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)
10.14	–	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)
10.15	–	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)
10.16	–	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)
10.16-01	–	Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.16. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.17	–	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)
10.18	–	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,

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		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)
10.19	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
10.20	–	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)
10.21	–	Interchange Agreement, executed April 14, 1982, between Comision 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)
10.22	–	Credit Agreement, dated as of February 12, 1996, as amended and restated as of February 8, 1999, between the Company, Chase Manhattan Bank, as agent, and Chase Bank of Texas, National Association, as Trustee. (Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
10.22-01	–	Amendment Agreement, dated as of February 8, 1999, to Exhibit 10.24. (Exhibit 10.24-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
10.23	–	Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 1. (Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.24	–	Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 2. (Exhibit 10.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.25	–	Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 3. (Exhibit 10.32 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.26	–	Spent Fuel Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Spent Fuel Trustee. (Exhibit 10.33 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.27	–	Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources

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		Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.28	–	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)
10.29	–	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)
†10.30	–	Form of Change of Control Agreement between the Company and certain key officers of the Company. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002)
††10.31	–	Form of Restricted Stock Award Agreement between the Company and certain key officers of the Company. (Exhibit 99.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.32	–	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)
†††10.33	–	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)
††††10.34	–	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)
10.35	–	El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)
10.36	–	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)
10.37	–	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)
10.38	–	Stock Option Agreements, dated as of January 1, 2001 and April 1, 2001, with Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997) (Exhibit 10.03 to Company’s Quarterly Report on Form 10-Q for quarter ended March 31, 2001)
10.39	–	Form of Directors’ Restricted Stock Award Agreement, dated as of May 10, 2001, between the Company and George W. Edwards, Jr. (Identical in all material respects to Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the

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		quarter ended June 30, 1999) (Exhibit 10.04 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.40	–	Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.41	–	Form of Stock Option Agreement, dated as of April 23, 2001, between the Company and Hector Puente. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998) (Exhibit 10.08 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.42	–	Stock Option Agreement, dated as of July 1, 2001, with Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997) (Exhibit 10.09 to Company’s Quarterly Report on Form 10-Q for quarter ended September 30, 2001)
10.43	–	Stock Option Agreement, dated as of October 1, 2001, with Mr. Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.44	–	Stock Option Agreement, dated as of November 5, 2001, with Gary R. Hedrick. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.45	–	Stock Option Agreement, dated as of November 12, 2001, with Terry Bassham. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.46	–	Stock Option Agreement, dated as of November 26, 2001, with Julius F. Bates. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.47	–	Restricted Stock Award Agreement, dated as of November 8, 2001 between the Company and for Mr. Gary R. Hedrick. (Identical in all material respects to Exhibit 99.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.48	–	Credit Agreement dated as of February 12, 1996, as amended and restated as of February 8, 1999 and January 28, 2002, among the Company, JPMorgan Chase Bank as Trustee, the lenders party hereto and JPMorgan Chase Bank, as Administrative Agent, Collateral Agent, and Issuing Bank.
10.49	–	Stock Option Agreements, dated as of January 1, 2002 and April 1, 2002, with Wilson Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.50	–	Stock Option Agreement, dated as of January 14, 2002, with Raul A. Carrillo, Jr. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)

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10.51	–	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)
10.52	–	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)
*10.52-01	–	First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.52.
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 107 of this report)
Exhibit 24 – Power of Attorney:
*24.01	–	Power of Attorney (set forth on page 106 of this report)
*24.02	–	Certified copy of resolution authorizing signatures pursuant to power of attorney
*31.01	–	Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.01	–	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99 – Additional Exhibits:
99.01	–	Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to Registration Statement No. 33-99744 on Form S-1)
99.02	–	Stock Option Agreement, dated as of January 17, 1997, with David H. Wiggs, Jr. (Exhibit 99.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)
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)

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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.

† Ten agreements, dated as of February 7, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Raul A. Carrillo, Jr.; Gary R. Hedrick; Kathryn Hood; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; Hector R. Puente; and Guillermo Silva; officers of the Company.

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

†† Nine agreements, dated as of February 28, 2001, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Gary R. Hedrick; Kathryn Hood; John C. Horne; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; and Guillermo Silva; officers of the Company.

Nine agreements, dated as of February 28, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Gary R. Hedrick; Kathryn Hood; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; Hector R. Puente; and Guillermo Silva; officers of the Company.

Two agreements, dated as of July 15, 2002, substantially 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, substantially identical in all 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, twelve agreements, dated as of January 1, 2002; April 1, 2002; July 1, 2002; and October 1, 2002; substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.

In lieu of non-employee director cash compensation, nine agreements, dated as of January 1, 2003; April 1, 2003; and July 1, 2003; substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.

Twelve agreements, dated as of May 21, 2003, substantially identical in all material respects to this Exhibit, were entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; James W. Cicconi; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; Charles A.

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Yamarone; James A. Cardwell; and Wilson K. Cadman; directors of the Company.

In lieu of non-employee director cash compensation, four agreements dated as of October 1, 2003, substantially identical in all material respects to this Exhibit, have been entered into with James W. Cicconi; Kenneth R. Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.

In lieu of non-employee director cash compensation, three agreements, dated as of January 2, 2004, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.

††††  In lieu of non-employee director cash compensation, one agreement, dated as of October 1, 2000, substantially identical in all material respects to this Exhibit, has been entered into with Wilson K. Cadman; a director of the Company.

In lieu of non-employee director cash compensation, four 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 Wilson Cadman and Kenneth Heitz; directors of the Company.

In lieu of non-employee director cash compensation, four 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 and Wilson K. Cadman; directors of the Company.

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

In lieu of non-employee director cash compensation, one agreement, dated as of January 2, 2004, substantially identical in all material respects to this Exhibit, has been entered into with Wilson K. Cadman; director of the Company.

(b) Reports on Form 8-K

No reports on Form 8-K were filed during the last quarter of 2003.

104

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.

105

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 Gary R. Hedrick, Terry Bassham, J. Frank Bates and Raul A. Carrillo, Jr., 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 15th day of March 2004.

EL PASO ELECTRIC COMPANY
By:	/s/    GARY R. HEDRICK
	Gary R. Hedrick President and Chief Executive Officer (Principal Executive Officer)

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

Signature	Title	Date
/s/    GARY R. HEDRICK         (Gary R. Hedrick)	President and Chief Executive Officer (Principal Executive Officer) and Director	March 15, 2004
/s/    TERRY BASSHAM         (Terry Bassham)	Executive Vice President, Chief Financial and Administrative Officer (Principal Financial Officer )	March 15, 2004
/s/    J. ROBERT BROWN         (J. Robert Brown)	Director	March 15, 2004
/s/    WILSON K. CADMAN         (Wilson K. Cadman)	Director	March 15, 2004
/s/    JAMES A. CARDWELL         (James A. Cardwell)	Director	March 15, 2004
/s/    JAMES W. CICCONI         (James W. Cicconi)	Director	March 15, 2004
/s/    GEORGE W. EDWARDS, JR.         (George W. Edwards, Jr.)	Director	March 15, 2004
/s/    RAMIRO GUZMAN         (Ramiro Guzman)	Director	March 15, 2004
/s/    JAMES W. HARRIS         (James W. Harris)	Director	March 15, 2004
/s/    KENNETH R. HEITZ         (Kenneth R. Heitz)	Director	March 15, 2004
/s/    PATRICIA Z. HOLLAND-BRANCH         (Patricia Z. Holland-Branch)	Director	March 15, 2004
/s/    MICHAEL K. PARKS         (Michael K. Parks)	Director	March 15, 2004
/s/    ERIC B. SIEGEL         (Eric B. Siegel)	Director	March 15, 2004
/s/    STEPHEN WERTHEIMER          (Stephen Wertheimer)	Director	March 15, 2004
/s/    CHARLES A. YAMARONE         (Charles A. Yamarone)	Director	March 15, 2004

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EX-10.52.01

EXHIBIT 10.52-01

FIRST AMENDED AND RESTATED INTERCONNECTION AGREEMENT

DATED OCTOBER 9, 2003

BETWEEN

EL PASO ELECTRIC COMPANY

AND

PUBLIC SERVICE COMPANY OF NEW MEXICO

FIRST REVISED SERVICE AGREEMENT NO. 47

SUPERSEDING ORIGINAL SERVICE AGREEMENT NO. 47

UNDER EL PASO ELECTRIC COMPANY

FERC ELECTRIC TARIFF ORIGINAL VOLUME NO. 1

EFFECTIVE DATE: OCTOBER             , 2003

Table of Contents

Article I		DEFINITIONS	1
	1.1	“Abnormal Condition”	2
	1.2	“Affiliate”	2
	1.3	“Afton Switching Station”	2
	1.4	“Agents”	2
	1.5	“Agreement”	2
	1.6	“Applicable Laws and Regulations”	2
	1.7	“Bankruptcy Laws”	2
	1.8	“Breaching Party”	2
	1.9	“Business Day”	2
	1.10	“Commercial Operation Date”	2
	1.11	“Commercially Reasonable Efforts”	2
	1.12	“Confidential Information”	3
	1.13	“Custodian”	3
	1.14	“Due Diligence”	3
	1.15	“Effective Date”	3
	1.16	“Emergency”	3
	1.17	“Environmental Laws”	3
	1.18	“EPE”	3
	1.19	“EPE Control Area”	3
	1.20	“EPE Interconnection Facilities”	4
	1.21	“EPE OATT”	4
	1.22	“EPE’s Palo Verde Facilities	4
	1.23	“EPE Transmission System”	4
	1.24	“Facility”	4
	1.25	“Federal Power Act”	4
	1.26	“FERC”	4
	1.27	“General Orders”	4
	1.28	“Generator”	4
	1.29	“Generator’s Interconnection Facilities”	4
	1.30	“Good Utility Practice”	5
	1.31	“Governmental Authority”	5
	1.32	“Governor Droop”	5
	1.33	“Hazardous Substances”	5
	1.34	“Interconnected Facilities”	5
	1.35	“Interconnection Point”	5
	1.36	“Interconnection Service”	5
	1.37	“Interconnection Studies”	5
	1.38	“Interconnection System Upgrades”	6
	1.39	“Interest Rate”	6
	1.40	“Metering Equipment”	6
	1.41	“NERC”	6
	1.42	“Non-Breaching Party”	6
	1.43	“Operating Agent”	6

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico i

	1.44	“Operating Committee”	6
	1.45	“Operation Date”	6
	1.46	“Participant”	6
	1.47	“Parties”	6
	1.48	“Party”	6
	1.49	“Person”	6
	1.50	“Power System Stabilizer (PSS)”	6
	1.51	“Protective Equipment”	7
	1.52	“Regional Transmission Organization” or “RTO”	7
	1.53	“Release”	7
	1.54	“Reliability Management System” or “RMS”	7
	1.55	“Security Coordinator”	7
	1.56	“SOCC”	7
	1.57	“Termination Costs”	7
	1.58	“Transmission Service Agreement”	7
	1.59	“WSCC”	7
	1.60	“WSCC Agreement”	7
	1.61	“WSCC Reliability Criteria Agreement”	7
Article II		TERM	8
	2.1	Effectiveness of this Agreement	8
	2.2	FERC Filing	8
	2.3	Term	8
	2.4	Material Adverse Change	9
	2.5	Survival	9
Article III		CONTINUING OBLIGATIONS AND RESPONSIBILITIES	9
	3.1	Interconnection Service Provided	9
	3.2	Scope of Interconnection Service	9
	3.3	Services Outside Scope of Agreement	10
	3.4	No Guarantees; Release	10
	3.5	Reporting Requirements	11
	3.6	Third Party Activity	11
	3.7	Compliance with EPE OATT and FERC Orders No. 888 and No. 889	11
Article IV		OPERATING COMMITTEE	11
	4.1	Operating Committee	11
	4.2	Responsibilities of the Operating Committee	12
	4.3	Effectiveness of Operating Committee Determinations	12
Article V		FACILITY INTERCONNECTION	12
	5.1	Establishment of Interconnection	12
	5.2	Necessary Easements, Permits, Licenses, Etc	12
	5.3	Design and Construction of Generator’s Interconnection Facilities	13
	5.4	Design and Construction of EPE Interconnection Facilities and Interconnection System Upgrades and Transmission Credits	13
	5.5	Subcontractors	15
	5.6	Rights of Access	15
	5.7	Course and Completion of Construction	16
	5.8	Timely Completion	17

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico ii

	5.9	Environmental Compliance and Procedures	17
	5.10	Generator Modeling Data	18
	5.11	Equipment Requirements	18
	5.12	Required Diagrams	18
	5.13	Required Personnel Information	18
	5.14	Use of Afton Switching Station by Third Parties	18
	5.15	Interconnected Facilities and Facility Additions, Modifications or Replacements	19
Article VI		ACCEPTANCE AND PERFORMANCE TESTING AND COMPLIANCE MONITORING	20
	6.1	Responsibility for Testing	20
	6.2	Responsibility for Modifications Following Testing	21
	6.3	Documentation of Results to EPE or the Operating Agent	21
	6.4	Facility Certification	21
	6.5	Transmission Service During Testing	21
	6.6	EPE Inspection Rights	22
	6.7	Generator Inspection Rights	22
	6.8	EPE’s Reviews, Inspections, and Approvals	22
Article VIII		INTERCONNECTION FACILITY COSTS AND BILLING	22
	7.1	Interconnection Construction Completion and Cost	22
	7.2	Invoices and Payments	23
	7.3	Adjustments	26
	7.4	Payment Not a Waiver	26
	7.5	Income Taxes	26
Article VIII		OPERATIONS	27
	8.1	General	27
	8.2	Obligations of Operating Agent	27
	8.3	Obligations of Generator	27
	8.4	Reliability Criteria	28
	8.5	Quality of Power	28
	8.6	Protection and System Quality	29
	8.7	Adjustments	29
	8.8	Switching and Tagging Procedures	29
	8.9	General Orders	30
	8.10	Generation Alert	30
Article IX		RELIABILITY MANAGEMENT SYSTEM	30
	9.1	Purpose	30
	9.2	Compliance	31
	9.3	Participant Status	31
	9.4	Payment of Sanctions	31
	9.5	Transfer of Control or Sale of Facility	31
	9.6	Failure to Comply with RMS	31
	9.7	Publication	31
	9.8	Third Parties	31
	9.9	Reserved Rights	32
	9.10	Termination	32

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico iii

	9.11	Mutual Agreement	32
	9.12	Severability	32
Article X		REACTIVE POWER	32
	10.1	Obligation to Supply Reactive Power	32
	10.2	Compensation	33
	10.3	Reactive Power Standards	33
	10.4	Failure to Supply Reactive Power	33
Article XI		OUTAGES, INTERRUPTIONS, AND DISCONNECTIONS	34
	11.1	Outage Scheduling	34
	11.2	Scheduled Maintenance and Coordination	34
	11.3	Other Maintenance and Coordination	34
	11.4	Unplanned Outages	34
	11.5	Disconnection	34
	11.6	Continuity of Service	35
Article XII		EMERGENCY AND ABNORMAL CONDITION PROCEDURES	35
	12.1	Emergency	35
	12.2	Notice of Emergency	36
	12.3	Immediate Action	36
	12.4	Disconnection of Facility in Event of Potential Emergency	36
	12.5	Audit Rights	37
	12.6	Abnormal Conditions	37
Article XIII		MAINTENANCE	38
	13.1	The Operating Agent Obligations	38
	13.2	Generator Obligations	38
	13.3	Maintenance Expenses	38
	13.4	Coordination	38
	13.5	Observation of Deficiencies	38
	13.6	Review of Maintenance Records	39
Article XIV		METERING	39
	14.1	General	39
	14.2	Testing	39
	14.3	Data Metered	39
	14.4	Data Available Upon Request	40
	14.5	Costs	40
Article XV		SAFETY	40
	15.1	General	40
	15.2	Environmental Releases	40
	15.3	Other Environmental Impact	40
Article XVI		COMMUNICATIONS	40
	16.1	Equipment	40
	16.2	Remote Terminal Unit	41
Article XVII		INFORMATION REPORTING	41
	17.1	General	41
	17.2	Compliance Monitoring Reporting	41
	17.3	Regulatory Agency Reporting	41
	17.4	Penalties	41

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico iv

Article XVIII		DOCUMENTATION	42
	18.1	General	42
	18.2	Drawings	42
Article XIX		FORCE MAJEURE	42
	19.1	Definition	42
	19.2	Performance Excused	43
	19.3	Labor Issues	43
	19.4	Payment Not Excused	43
Article XX		INDEMNIFICATION	43
	20.1	INTERCONNECTION INDEMNITY	43
	20.2	RECIPROCAL INDEMNITY	43
	20.3	DAMAGE DISCLAIMER	44
	20.4	Indemnities Reformed	44
	20.5	Indemnification Procedures	44
	20.6	Additional Indemnification Provisions	45
	20.7	Survival	45
Article XXI		INSURANCE	45
	21.1	Generator	45
	21.2	EPE or Operating Agent	45
	21.3	Notice of Cancellation	46
	21.4	Self-Insurance	46
Article XXII		DEFAULT	46
	22.1	General	46
	22.2	Events Constituting Breach	46
	22.3	Notice by Breaching Party	47
	22.4	Cure and Default	47
	22.5	Continued Operations	47
	22.6	Upon Default	48
	22.7	Generator’s Default in Payment for Equipment	48
Article XXIII		TERMINATION	48
	23.1	Expiration of Term	48
	23.2	Termination in the Event of Default	48
	23.3	Survival	48
	23.4	Disconnection and Disposition of Facilities Upon Termination	49
Article XXIV		CREDITWORTHINESS	49
Article XXV		RELATIONSHIP OF THE PARTIES	49
Article XXVI		REPRESENTATIONS AND WARRANTIES	49
	26.1	Representations of EPE	49
	26.2	Representations of Generator	50
	26.3	Representations of Each Party	51
Article XXVII		ASSIGNMENT	51
	27.1	General	51
	27.2	EPE	51
	27.3	Generator	51
	27.4	No Relief in Event of Assignment	51
Article XXVII		CONFIDENTIALITY	51

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico v

	28.1	General	51
	28.2	Scope	52
	28.3	Rights in Confidential Information	52
	28.4	Standard of Care	52
	28.5	Required Disclosures	52
	28.6	Possession of Confidential Information at Termination of Agreement	52
	28.7	Remedies Regarding Confidentiality	52
Article XXIX		DISPUTE RESOLUTION	53
	29.1	Dispute Resolution by Operating Committee	53
	29.2	Dispute Resolution by Senior Management	53
	29.3	Arbitration	53
	29.4	FERC Jurisdiction Over Certain Disputes	54
	29.5	Continued Performance	55
Article XXX		MISCELLANEOUS	55
	30.1	Partial Invalidity	55
	30.2	Successors Included	55
	30.3	Applicable Laws and Regulations	55
	30.4	Choice of Law and Jurisdiction	55
	30.5	Entire Agreement	55
	30.6	Counterparts to this Agreement	56
	30.7	Amendments	56
	30.8	Amendments Included	56
	30.9	Notices	56
	30.10	Waivers	57
	30.11	No Third Party Beneficiaries	57
	30.12	Further Assurances	57
	30.13	Headings	57
	30.14	Articles	57
	30.15	Number, Gender, and Inclusion	58
	30.16	Good Utility Practice	58
	30.17	Succession Upon Membership in an RTO	58
	30.18	Notification of Change of Operating Agent	58
	30.19	Amended and Restated	58

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico vi

FIRST AMENDED AND RESTATED INTERCONNECTION AGREEMENT

This First Amended and Restated Interconnection Agreement (as defined below, “Agreement”) is made and entered into as of this 9^th day of OCTOBER, 2003, by and between El Paso Electric Company (“EPE”), a corporation organized under the laws of the State of Texas, and Public Service Company of New Mexico (“Generator”), a corporation organized under the laws of the State of New Mexico.

W I T N E S S E T H

WHEREAS, EPE is engaged in the transmission and distribution of electric energy in the States of New Mexico and Texas;

WHEREAS, EPE owns and operates the new Afton Switching Station near Afton, New Mexico and 345 kV transmission lines from the existing EPE Transmission System to Afton Switching Station;

WHEREAS, EPE and Generator have entered into an Interconnection Agreement on May 23, 2002 (“Interconnection Agreement”);

WHEREAS, Generator has constructed, owns and operates an electric generating facility (as defined below, “Facility”) located near Afton, New Mexico;

WHEREAS, in accordance with the Interconnection Agreement, Generator has constructed the new Afton Switching Station and 345 kV transmission lines from Afton Switching Station to EPE’s existing transmission system;

WHEREAS, in accordance with the Interconnection Agreement, Generator has interconnected the Facility with the EPE Transmission System at the Afton Switching Station;

WHEREAS, this Agreement does not provide for transmission, distribution or ancillary services and separate arrangements are required for such services; and

WHEREAS, EPE and Generator desire to amend and restate the Interconnection Agreement by allocating the costs of interconnection facilities in accordance with FERC policy as set forth herein.

NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows:

Article I

DEFINITIONS

For purposes of this Agreement, the following terms shall have the following meanings.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 1

1.1 “Abnormal Condition” means any condition at the Facility, on the Interconnected Facilities, on the EPE Transmission System, or on the transmission system of other utilities which is outside normal operating parameters such that facilities are operating outside their normal ratings or reasonable operating limits have been exceeded and would result in an Emergency if these conditions continue. Any condition or situation that results from lack of sufficient planned generating capacity to meet load requirements or that results solely from economic conditions shall not, standing alone, constitute an Abnormal Condition.

1.2 “Affiliate” means, with respect to any Person, any other Person (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such Person. For this purpose, “control” means the direct or indirect ownership of fifty percent (50%) or more of the outstanding capital stock or other equity interests having ordinary voting power.

1.3 “Afton Switching Station” means the 345 kV substation constructed by Generator, and owned and operated by EPE near Afton, New Mexico as depicted in Appendices B and E.

1.4 “Agents” means the officers, directors, shareholders, employees or agents acting on behalf of a Party or group of Parties.

1.5 “Agreement” means this First Amended and Restated Interconnection Agreement between EPE and Generator, including attachments, exhibits, and appendices.

1.6 “Applicable Laws and Regulations” means all applicable federal, state and local laws, codes, ordinances, rules and regulations, and all duly promulgated orders and other duly authorized actions, as amended from time to time, and whether now existing or hereafter enacted, promulgated, entered or otherwise arising, of any Governmental Authority having jurisdiction over the Parties and/or their respective facilities.

1.7 “Bankruptcy Laws” shall have the meaning set forth in Article 22.2(c).

1.8 “Breaching Party” shall have the meaning set forth in Article 22.2.

1.9 “Business Day” means any day on which the Federal Reserve member banks are open for business. A Business Day shall commence at 8:00 a.m. and close at 5:00 p.m., local time, at the location of the relevant Party’s principal place of business, or at such other location as the context may require. The relevant Party, in each instance unless otherwise specified, shall be the Party to which the notice, payment, or delivery is being sent and by which the notice, payment, or delivery is being received.

1.10 “Commercial Operation Date” means the first day on which the Facility generates electric energy, other than test energy, for sale.

1.11 “Commercially Reasonable Efforts” means efforts by a Party to perform the particular obligation under this Agreement using skills, time and funds which are customary and reasonable in transactions of the kind and nature contemplated by this Agreement in order for such Party to satisfy such obligation under this Agreement.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 2

1.12 “Confidential Information” means any confidential, proprietary, or trade secret information associated with a plan, specification, pattern, procedure, design, device, list, concept, policy, or compilation relating to the present or planned business of a Party (including all information relating to a Party’s technology, research and development, business affairs and pricing), which is designated as “Confidential” by the Party supplying the information, whether conveyed orally, in writing, electronically, through inspection, or otherwise prior to or after the Effective Date. Any Confidential Information designated as such by a Party that is conveyed in writing or electronically must clearly be designated or marked as confidential on the face of the document or electronic transmission. To the extent that the Confidential Information is designated as such by a Party orally or through inspection, the Party providing such information must inform the Party receiving such information that it is Confidential Information.

1.13 “Custodian” shall have the meaning set forth in Article 22.2(c).

1.14 “Due Diligence” means the exercise of good faith efforts to perform a required act on a timely basis and in accordance with Good Utility Practice using the necessary technical resources and personnel.

1.15 “Effective Date” means the date set forth in Article 2.1 of this Agreement.

1.16 “Emergency” means (a) a condition or situation which, in the judgment of the Operating Agent, requires immediate manual or automatic action to prevent (i) endangerment of life or property, or (ii) loss of firm load, equipment damage, or tripping of system elements that could adversely affect the reliability of the EPE Transmission System or the electrical transmission systems of others to which the EPE Transmission System is directly or indirectly connected, and which requires that the output of the Facility be adjusted to help avoid or mitigate such condition or situation, and (b) a condition or situation which Generator deems imminently likely to (i) endanger life or property, or (ii) adversely affect or impair the reliability of the Facility. The conditions or situations described in Articles 1.16(a)(ii) and 1.16(b)(ii) include equipment damage, danger of instability, voltage collapse or uncontrollable cascading outages. Any condition or situation that results from lack of sufficient planned generating capacity to meet load requirements or that results solely from economic conditions shall not, standing alone, constitute an Emergency.

1.17 “Environmental Laws” means federal, state, and local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or administrative orders (and any amendments thereto) relating to pollution or protection of the environment, archaeological or natural resources, or human health and safety, including laws relating to exposures, Releases or threatened Releases of Hazardous Substances (including Releases or threatened Releases to ambient air, surface water, groundwater, land, surface and subsurface strata) or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, Release, transport, or handling of Hazardous Substances.

1.18 “EPE” shall have the meaning set forth in the first paragraph of this Agreement.

1.19 “EPE Control Area” means the power system where EPE is responsible for matching generation within the control area and net transactions with other control areas with the prevailing real-time

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 3

electrical load in the control area, for maintaining within limits generally accepted as Good Utility Practice scheduled interchange with neighboring control areas, and for maintaining frequency within reasonable limits in accordance with Good Utility Practice.

1.20 “EPE Interconnection Facilities” means all equipment and other facilities, including Protective Equipment and Metering Equipment owned, operated and maintained by EPE from the Generator’s side of air switch 32485 to the Interconnection Point. The EPE Interconnection Facilities are listed in Appendix B.

1.21 “EPE OATT” means EPE’s Open Access Transmission Tariff filed with FERC in accordance with FERC’s Order No. 888, and any successor transmission service tariff thereto, including any such successor tariff of a Regional Transmission Organization to which EPE transfers operating authority over the EPE Transmission System.

1.22 “EPE’s Palo Verde Facilities” means three 500 kv lines and related facilities, that extend 165 miles in total from the Palo Verde Nuclear Generating Station near Phoenix, Arizona, with two of the lines extending to the Westwing substation and one extending to the Kyrene substation, all facilities entirely in Arizona.

1.23 “EPE Transmission System” means all of the facilities owned by EPE, including the Interconnection System Upgrades that are made available for the purpose of providing transmission service under the EPE OATT.

1.24 “Facility” means Generator’s electric generating facility with an output of 142 MW (Summer) and 149 MW (Winter) located near Afton, New Mexico, together with the other property, facilities, and equipment owned and/or operated by Generator up to and including the output terminals of the generator as indicated in Appendix A.

1.25 “Federal Power Act” means the Federal Power Act, 16 U.S.C. § 791a et seq., as amended from time to time.

1.26 “FERC” means the Federal Energy Regulatory Commission, or any successor federal agency.

1.27 “General Orders” means the set of standard operating procedures, as modified from time to time, by which the Operating Agent operates the EPE Transmission System and which are applicable to generating facilities connected to that transmission system, including, at the Effective Date, the Facility.

1.28 “Generator” shall have the meaning set forth in the first paragraph of this Agreement.

1.29 “Generator’s Interconnection Facilities” means all equipment and other facilities, including certain Protective Equipment, owned, operated and maintained by Generator, from the generator output terminals up to the Generator’s side of air switch 32485 as indicated in Appendices B (Attachment 1) and E, including any modifications, additions, or upgrades made to such facilities, which, in conjunction with the EPE Interconnection Facilities, are necessary to connect the Facility to the EPE Transmission System at the Afton Switching Station.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 4

1.30 “Good Utility Practice” means any of the practices, methods, and acts required, approved, or engaged in by the WSCC, NERC, RTO (if applicable) or a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods, and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety, and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act; rather, it is intended to be a spectrum of practices, methods, and acts generally accepted by the electric utility industry in the WSCC region. Good Utility Practice shall include compliance with Applicable Laws and Regulations.

1.31 “Governmental Authority” means any entity with proper jurisdiction or authority over the Parties and/or their respective facilities, including (i) a federal, tribal, state, local or municipal governmental body; (ii) a governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise administrative, executive, judicial, legislative, policy, regulatory or taxing authority or power; and (iii) a court or governmental tribunal.

1.32 “Governor Droop” means the governor response characteristic (speed versus output characteristic) defining the decrease in frequency needed to cause generator output to go from no load to full load.

1.33 “Hazardous Substances” means (a) any petrochemical or petroleum products, oil, coal ash, radioactive materials, radon gas, asbestos in any form that is or could be friable, urea formaldehyde foam insulation and transformers or other equipment that contains dielectric fluid that may contain polychlorinated biphenyls; (b) any chemicals, materials, or substances defined as or included in the definition of “hazardous substances,” “hazardous wastes,” “hazardous materials,” “hazardous constituents,” “restricted hazardous materials,” “extremely hazardous substances,” “toxic substances,” “contaminants,” “pollutants,” “toxic pollutants,” or words of similar meaning and regulatory effect under any applicable Environmental Law; or (c) any other chemical, material, or substance, exposure to which is prohibited, limited, or regulated by any applicable Environmental Law.

1.34 “Interconnected Facilities” means the EPE Interconnection Facilities and the Generator’s Interconnection Facilities.

1.35 “Interconnection Point” means the point where the EPE Interconnection Facilities attach to the bus bar within the Afton Switching Station as delineated in Appendices B and E.

1.36 “Interconnection Service” means the service provided by EPE to interconnect the Facility, via Generator’s Interconnection Facilities, with the EPE Transmission System.

1.37 “Interconnection Studies” means the studies performed by or on behalf of EPE pursuant to an interconnection request by Generator which have determined the design, specifications and cost estimate for the Interconnected Facilities and the Interconnection System Upgrades required to accommodate the interconnection of the Facility.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 5

1.38 “Interconnection System Upgrades” means the additions, modifications, and upgrades to the EPE Transmission System, including Protective Equipment and Metering Equipment, required beyond the Interconnection Point to accommodate the interconnection of the Facility to the EPE Transmission System through the EPE Interconnection Facilities as identified in Appendix B, including any modifications, additions, or upgrades made to such facilities.

1.39 “Interest Rate” means the prime interest rate for currency as published from time to time under “Money Rates” by The Wall Street Journal, or its successor (or, if no longer so published, any substitute mutually agreeable to the Parties), as of the payment due date and/or default date, plus two (2) percent; provided, however, that in no event shall the Interest Rate exceed the maximum interest rate permitted by Applicable Laws and Regulations.

1.40 “Metering Equipment” means all metering equipment to be installed at the Facility and at or near the Interconnection Point and Afton Switching Station. Metering Equipment is identified in Appendices A, B, and D.

1.41 “NERC” means the North American Electric Reliability Council, or any successor organization.

1.42 “Non-Breaching Party” shall have the meaning set forth in Article 22.2(g).

1.43 “Operating Agent” shall mean the entity that operates the EPE Transmission System. On the Effective Date of this Agreement, EPE is the Operating Agent for the EPE Transmission System.

1.44 “Operating Committee” shall have the meaning set forth in Article 4.1.

1.45 “Operation Date” means the day upon which the Interconnected Facilities, Interconnection System Upgrades and Facility have been completed to EPE’s and Generator’s mutual satisfaction and energized in parallel operation as confirmed in a written notice provided by EPE to Generator, which occurred January 1, 2003.

1.46 “Participant” has the meaning as stated in Article 9.3.

1.47 “Parties” means EPE (including in its capacity as Operating Agent) and Generator or the successor or permitted assignee of the rights and obligations of any of the foregoing under this Agreement.

1.48 “Party” means one of the Parties.

1.49 “Person” means an individual, partnership, corporation (including a business trust), limited liability company, joint stock company, trust, unincorporated association, joint venture or other entity or a government or any political subdivision or agency thereof.

1.50 “Power System Stabilizer (PSS)” means a control system applied at a generator that monitors variables such as current, voltage and shaft speed and sends the appropriate control signals to the voltage regulator to damp system oscillations.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 6

1.51 “Protective Equipment” means such protective relay systems, locks and seals, breakers, automatic synchronizers, associated communication equipment and other control schemes and protective apparatus as is reasonably necessary under Good Utility Practice and standards of EPE for the operation of the Facility in parallel with the EPE Transmission System and to permit the facilities of EPE and the Facility to operate reliably and safely.

1.52 “Regional Transmission Organization” or “RTO” means an entity approved by FERC to assume responsibility for providing electric transmission services and certain operational functions in a specific region in accordance with FERC Order No. 2000 or any other Applicable Laws and Regulations (including, but not limited to, other FERC orders).

1.53 “Release” means any release, spill, leak, discharge, disposal, pumping, pouring, emission, emptying, injection, leaching, dumping, escape into or through the environment of any Hazardous Substance.

1.54 “Reliability Management System” or “RMS” means the contractual reliability management program implemented through the WSCC Reliability Criteria Agreement, Article IX of this Agreement, and any similar contractual arrangement(s).

1.55 “Security Coordinator” means the entity authorized by the WSCC to have the final authority to direct electric system operations to prevent or remedy problems or disturbances that have regional impacts.

1.56 “SOCC” means System Operations Control Center.

1.57 “Termination Costs” means the costs incurred by or on behalf of EPE upon termination of this Agreement in accordance with Article XXIII in taking one or more of the following actions: (a) returning or canceling pending orders made by EPE for equipment or facilities required for the interconnection contemplated by this Agreement; (b) removing any portion of the EPE Interconnection Facilities or Interconnection System Upgrades; and (c) performing such work as may be necessary to ensure the safety of persons and property and to preserve the integrity of the EPE Transmission System.

1.58 “Transmission Service Agreement” means any transmission service agreements between Generator and EPE, excluding any agreement for transmission service that is provided over EPE’s Palo Verde Facilities.

1.59 “WSCC” means the Western Systems Coordinating Council, or any successor organization.

1.60 “WSCC Agreement” means the Western Systems Coordinating Council Agreement dated March 20, 1967.

1.61 “WSCC Reliability Criteria Agreement” means the Western Systems Coordinating Council Reliability Criteria Agreement dated June 18, 1999, among the WSCC and certain members of WSCC.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 7

Article II

TERM

2.1 Effectiveness of this Agreement. Article 2.2 and the fourth sentence of this Article 2.1 of this Agreement shall become effective upon execution by the Parties. The remaining provisions of this Agreement shall become effective on the effective date specified by FERC in accepting this Agreement (“Effective Date”) under Section 205 of the Federal Power Act. This Agreement shall supercede the Interconnection Agreement upon the Effective Date. Notwithstanding the foregoing and with respect to this Agreement, no Party shall take any action which is inconsistent with the terms of this Agreement and Applicable Laws and Regulations during the period between execution of this Agreement and acceptance by FERC or earlier termination of this Agreement.

2.2 FERC Filing.

2.2.1 Within a reasonable time after execution of this Agreement by the Parties, EPE shall file this Agreement with FERC as an amended “Rate Schedule” within the meaning of Part 35 of FERC’s regulations and with any other Governmental Authority to the extent required by Applicable Laws and Regulations. Each of the Parties shall support this Agreement in its current form at FERC when filed. Generator shall reasonably cooperate with EPE with respect to obtaining FERC approval of such FERC filing and provide any information, including testimony, reasonably required by EPE to comply with the applicable FERC filing requirements.

2.2.2 Promptly upon execution by the Parties of any amendment to this Agreement, EPE shall, if necessary, file such amendment with FERC and with any other Governmental Authority, to the extent required by Applicable Laws and Regulations. Each of the Parties shall support any such amendment at FERC when filed. Generator shall reasonably cooperate with EPE with respect to obtaining FERC approval of such FERC filing and provide any information, including testimony, reasonably required by EPE to comply with the applicable FERC filing requirements.

2.2.3 If FERC requires conditions to or modifications of any of the terms, conditions or provisions agreed to herein or in an amendment hereto and: (i) neither Party notifies the other Party in writing within fourteen (14) calendar days following receipt of FERC’s order that the notifying Party takes exception to FERC’s order, the FERC-ordered modifications and/or conditions shall become part of this Agreement as an amendment or appendix; or (ii) the Party taking exception to FERC’s conditions or modifications gives fourteen (14) calendar days notice (following receipt of FERC’s order) to the other Party of such exception, then the Parties shall promptly negotiate an amendment to this Agreement acceptable to FERC and providing similar benefit, rights, or effect to the Parties. Any such amendment shall be effective when accepted for filing by FERC. For purposes of this Article 2.2.3, each Party reserves and may exercise all of its rights under Applicable Laws and Regulations.

2.3 Term. This Agreement shall continue in full force and effect until a mutually agreed termination date; provided, however, that such termination date shall be no later than the date on which the Facility permanently ceases commercial operation; and provided further that this

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Agreement may be terminated earlier (a) upon a Party’s default in accordance with the provisions of Article 23.2 or (b) by the mutual agreement of the Parties or as explicitly provided elsewhere in this Agreement. Unless no longer required by FERC, any termination of this Agreement permitted hereunder shall not take effect until the filing at FERC of a notice of termination of this Agreement which notice is accepted for filing by FERC.

2.4 Material Adverse Change. In the event of a change in law or regulation after the Effective Date that has a material adverse effect, or may reasonably be expected to have a material adverse effect, on a Party’s ability to perform under this Agreement, the Parties shall negotiate in good faith any amendment or amendments to this Agreement necessary to adapt the terms of this Agreement to such change in law or regulation. If the Parties are unable to reach agreement on any such amendments within sixty (60) days of the commencement of their negotiations, each Party reserves and may exercise all its rights under Applicable Laws and Regulations.

2.5 Survival. The applicable provisions of this Agreement shall continue in effect after cancellation, expiration, or termination of this Agreement to provide for final billings, billing adjustments, and the determination and enforcement of liability and indemnification obligations arising from acts or events that occurred while this Agreement was in effect. In addition, upon termination of this Agreement subject to the terms of Article 23, Generator shall be responsible for any Termination Costs incurred by or on behalf of EPE.

Article III

CONTINUING OBLIGATIONS AND RESPONSIBILITIES

3.1 Interconnection Service Provided. EPE shall provide Generator with Interconnection Service for the Facility, as such service is defined in Article 1.36 and described in this Article III. EPE shall not provide Interconnection Service under this Agreement for any other generating units, wherever located. Any other generating units shall be covered by a separate interconnection agreement or an amendment of this Agreement as provided for in Article 3.2.3.

3.2 Scope of Interconnection Service.

3.2.1 Interconnection Service shall consist of the services necessary to allow the physical interconnection of the Facility pursuant to the terms of this Agreement. Interconnection Service does not mean and shall not include transmission service, ancillary services, losses, or any other service available under the EPE OATT. Specifically, Interconnection Service shall not include the purchase or sale of energy or ancillary services to or from the Facility beyond the Interconnection Point, or the delivery of energy or ancillary services from the Facility beyond the Interconnection Point, which services shall be provided separately under the EPE OATT or by others under separate agreements, as applicable.

3.2.2 Generator shall be responsible for (a) making arrangements under the EPE OATT for transmission and ancillary services on the EPE Transmission System, and under other applicable tariffs for such services on other transmission system(s), associated with the injection or delivery of the capacity and/or energy produced by the Facility beyond the Interconnection Point, which services shall not be provided under the terms of this Agreement, (b) obtaining capacity and/or energy to satisfy its Facility service or other requirements, and (c) making

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arrangements under applicable tariffs for transmission services, losses, and ancillary services associated with the use of the EPE Transmission System for the injection or delivery of capacity and/or energy to other generating facilities owned by Generator for the purpose of supplying facility service or for any other use. EPE makes no representations to Generator regarding the availability of transmission service on the EPE Transmission System, and Generator agrees that the availability of such transmission service may not be inferred or implied from this Agreement. Generator must request such transmission service in accordance with the EPE OATT.

3.2.3 In the event of an increase in the output of the Facility or other material change or modification to the configuration and/or operation of the Facility, the Parties shall negotiate appropriate revisions to this Agreement, including, as necessary, the performance by EPE of studies to determine the effects of such increase or change, and changes to the specifications or requirements set forth in the Appendices to this Agreement, as necessary to permit EPE to provide Interconnection Service to the Facility under this Agreement in a safe, secure and reliable manner.

3.3 Services Outside Scope of Agreement.

3.3.1 This Agreement provides only for interconnection of the Facility with the EPE Transmission System at the Afton Switching Station. Nothing in this Agreement shall be read as a request by Generator, or a commitment by EPE, to install any facilities other than those necessary to interconnect the Facility with the EPE Transmission System at the Afton Switching Station.

3.3.2 This Agreement does not obligate any Party to purchase, sell, transmit or otherwise provide any rights other than Interconnection Service. This Agreement does not obligate any Party to provide, or entitle any Party to receive, any transmission or other service not expressly provided for herein. This Agreement does not provide a right to inject or transmit energy which right shall be realized through the necessary arrangements for transmission rights and service, including mitigation related to transmission service, if any. Each Party is responsible for making any arrangements necessary for it to receive any transmission or other service not expressly provided for herein that it may desire from the other Party or any other Person. Notwithstanding any other provision of this Agreement, nothing herein shall be construed as a relinquishment or foreclosure of any rights to transmission credits to which Generator may be entitled, now or in the future, as a result of, or otherwise, associated with, the transmission capacity, if any, created by the Interconnection System Upgrades, if any.

3.3.3 This Agreement does not provide for the injection, sale or purchase of power or energy from or to the Facility. Upon Generator’s request, construction, back-up, start-up, auxiliary, station, and maintenance power required for the Facility at the Facility site shall be provided under a separate agreement or any applicable tariff.

3.4 No Guarantees; Release. EPE (which, for the purposes of this Article 3.4, shall be deemed to include the Operating Agent) does not warrant against the occurrence of, and Generator releases EPE from any and all claims or damages associated with: (a) damage to Generator’s Interconnection Facilities or the Facility resulting from electrical transients, or (b) any

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interruption in the availability of the EPE Interconnection Facilities, or any Interconnection System Upgrades, except, in the case of subpart (a) or (b), to the extent determined to be attributable to the negligence of, willful misconduct of, or default under Article XXII by EPE. Generator does not warrant against the occurrence of, and EPE releases Generator from any and all claims or damages associated with: (y) damage to the EPE Interconnection Facilities, any Interconnection System Upgrades, or the EPE Transmission System resulting from electrical transients, or (z) any interruption in the availability of Generator’s Facility, except, in the case of subpart (y) or (z), to the extent determined to be attributable to Generator’s negligence, willful misconduct or default under Article XXII.

3.5 Reporting Requirements. Each Party shall notify the other Party promptly when it becomes aware of its inability to comply with the terms and conditions of this Agreement, and provide a sufficient explanation of its inability to comply, including the date, duration, and reasons for its inability to comply, and corrective actions taken; provided that such notification shall not release such Party from its obligation to comply with this Agreement, except as provided under Article XIX.

3.6 Third Party Activity. During the term of this Agreement, other Persons may develop, construct or acquire, and operate generating facilities in EPE’s service territory, and reservations of transmission service by such Persons under the EPE OATT may adversely affect the availability of transmission service for the Facility’s electric output. EPE has no obligation to disclose to Generator any information regarding such third party activity, except as may be required under the EPE OATT or under this Agreement subject to the provisions of Article 3.7. To the extent that such third party activity has, or EPE reasonably expects the third party activity to have, a material adverse impact on the operation of the Facility or the Interconnected Facilities, EPE shall, subject to Article 3.7, disclose to Generator such material information as is necessary for Generator to understand the nature and extent of such adverse impact and the viable remedies.

3.7 Compliance with EPE OATT and FERC Orders No. 888 and No. 889. Nothing in this Agreement shall be deemed or construed to obligate EPE to provide or make available to Generator any information in violation of the EPE OATT, FERC Orders No. 888 and No. 889 or any other Applicable Laws and Regulations.

Article IV

OPERATING COMMITTEE

4.1 Operating Committee. Within fifteen (15) days after the Effective Date, each Party shall designate a primary and alternate representative to serve on an operating committee (“Operating Committee”), which shall meet periodically to ensure effective cooperation in system planning, to deal promptly with the various operating and technical issues that may arise during the term of this Agreement, and to attempt to resolve any disputes that may arise under this Agreement, as more specifically described in Article 4.2. Each primary and alternate representative shall be authorized, on behalf of the designating Party, to act with respect to all matters delegated to the Operating Committee. Each Party shall promptly notify the other Party of the designation of its primary and alternate representatives and of any subsequent changes in such designations in accordance with Article 30.9.

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4.2 Responsibilities of the Operating Committee. The Operating Committee shall have the following responsibilities and functions, each of which shall be performed consistent with the terms and conditions of this Agreement and Good Utility Practice: (a) to establish general policies to be followed in the coordination of the operation and maintenance of the Interconnected Facilities; (b) to establish procedures and standard practices, consistent with the terms and conditions of this Agreement, for guidance for each Party’s system controllers and other operating personnel regarding the interconnected operations of the Afton Switching Station and the Interconnected Facilities; (c) to establish detailed procedures to govern in the event of an Emergency; (d) to establish detailed procedures and standard practices for metering, communications, and control facilities; (e) to establish the plan for disconnection of the Facility at the termination of this Agreement; (f) to establish other procedures and standard practices as may be needed from time to time and to engage in other activities consistent with the terms and conditions of this Agreement, provided that the Operating Committee shall not have the authority to modify or amend any term or condition of this Agreement; and (g) to attempt to resolve any disputes that may arise under this Agreement in accordance with Article 29.1.

4.3 Effectiveness of Operating Committee Determinations. All determinations made by the Operating Committee, including the establishment of any procedure or standard practice, within the scope of the Operating Committee’s responsibilities set forth in Article 4.2, shall be effective when signed by one designated representative of each Party and, if necessary, accepted for filing or approved by FERC.

Article V

FACILITY INTERCONNECTION

5.1 Establishment of Interconnection. The Facility constructed by Generator shall be interconnected to the EPE Transmission System at the Afton Switching Station, such interconnection being further described in Appendices A, B, and E. Appendix E may be revised by mutual written agreement of the Parties. Pursuant to this Agreement, the Parties shall, during the term of this Agreement, continue in service the existing transmission lines and essential terminal equipment, to the extent required to establish and maintain a reliable interconnection.

5.2 Necessary Easements, Permits, Licenses, Etc. Subject to Articles 5.6.1 and 5.6.2, each Party shall diligently pursue all rights, easements, permits, licenses, certificates and properties necessary to construct, own and maintain its portion of the Interconnected Facilities and the Interconnection System Upgrades. If a Party cannot reasonably acquire all the rights, easements, permits, licenses, certificates and properties necessary to construct, own and maintain its portion of the Interconnected Facilities and/or Interconnection System Upgrades, the Party shall promptly provide written notice to the other Party indicating its inability. After such notice, Generator shall have thirty (30) days to authorize EPE to initiate and diligently pursue the following at Generator’s expense: (a) condemnation proceedings, (b) alternate routes, designs, methods or procedures necessary for the construction, ownership, or maintenance of the Interconnected Facilities and/or Interconnection System Upgrades, or (c) any other appropriate action mutually agreed upon by the Parties. Each Party shall also pursue with Due Diligence and maintain all necessary governmental approvals, permits, licenses and inspections necessary for its performance of this Agreement. Generator shall also assign to

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EPE, that portion of Generator’s rights under the Bureau of Land Management (“BLM”) Right of Way NMNM102630 (“BLM 102630 R-O-W”) for the land underlying the Interconnection System Upgrades and the portion of the EPE Interconnection Facilities delineated as TRACT 3 on Appendix F. Contemporaneous with the partial assignment of the BLM 102630 R-O-W, the grants of access pursuant to Articles 5.6.1 and 5.6.2 shall become effective. All expenses associated with such transfer shall be at Generator’s cost and shall be a part of the cost of Interconnection System Upgrades and delineated in Appendix B.

5.3 Design and Construction of Generator’s Interconnection Facilities.

5.3.1 Unless the Parties agree otherwise in writing, Generator shall, at its own expense, design, procure, construct, install, operate, maintain and repair/replace Generator’s Interconnection Facilities.

5.3.2 Protective Equipment to be installed by Generator is set forth in Appendix A. This Protective Equipment shall be subject to review and approval by EPE, which approval shall not be unreasonably withheld or denied. EPE’s review and/or approval shall not be deemed an endorsement of any equipment nor as any warranty as to the fitness, safety, durability or reliability of any equipment.

5.3.3 Generator shall design, procure, construct and install Generator’s Interconnection Facilities in accordance with applicable Interconnection Studies and Good Utility Practice.

5.3.4 At Generator’s expense, Generator’s Interconnection Facilities shall be constructed by Generator or, at Generator’s option, a third party contractor to be selected by Generator. Notwithstanding the foregoing, Generator understands and agrees that EPE shall be responsible for closing the connection of the EPE Interconnection Facilities and Generator’s Interconnection Facilities.

5.3.5 Generator shall, at its own expense, operate, maintain and repair/replace Generator’s Interconnection Facilities in accordance with Articles VIII and XIII.

5.4 Design and Construction of EPE Interconnection Facilities and Interconnection System Upgrades, and Transmission Credits.

5.4.1 At Generator’s expense, Generator shall design, procure equipment for and construct the EPE Interconnection Facilities and the Interconnection System Upgrades required to connect the Facility to the existing EPE Transmission System.

5.4.2 At Generator’s expense, EPE will review and approve all design, procurement of equipment and construction of the EPE Interconnection Facilities and Interconnection System Upgrades. EPE’s approval shall not be unreasonably withheld or denied. EPE’s review and/or approval shall not be deemed an endorsement of any design, facility or equipment nor as any warranty as to the fitness, safety, durability or reliability of any design, facility or equipment.

5.4.3 At Generator’s expense, EPE shall own, operate, maintain, and repair/replace the EPE Interconnection Facilities.

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5.4.4 EPE shall own the Interconnection System Upgrades, including Afton Switching Station. After the Operation Date, EPE shall, at its own expense, operate, maintain and repair/replace Interconnection System Upgrades in accordance with Good Utility Practice.

5.4.5 The cost to design, engineer, procure equipment, and construct the EPE Interconnection Facilities and the Interconnection System Upgrades is set forth in Appendix B, subject to audit by EPE pursuant to Article 7.1.3 below.

5.4.6 The schedule for Generator and EPE to perform the design, procurement of equipment, construction and testing is set forth in Appendix C.

5.4.7 The design, procurement, construction and installation of the EPE Interconnection Facilities and the Interconnection System Upgrades shall be in accordance with applicable Interconnection Studies and Good Utility Practice. The EPE Interconnection Facilities and Interconnection System Upgrades must be sufficient, as designed and built, to deliver the full Facility output as defined in Article 1.24 to the Interconnection Point and to enable the Facility to receive capacity necessary to satisfy its operational requirements (not to exceed 10 MW of capacity).

5.4.8 As of the Effective Date, the Parties agree that the Interconnection System Upgrades and the EPE Interconnection Facilities have been installed. The costs of the Interconnection System Upgrades and the EPE Interconnection Facilities, subject to audit by EPE pursuant to Article 7.1.3 below, are delineated in Exhibit B.

5.4.9 Notwithstanding any other provision of this Agreement, Generator shall not be responsible for any costs or expenses associated with the design, procurement, construction, installation, testing, operation, maintenance, repair/replacement, or any modifications or upgrades to the EPE Transmission System that are undertaken in order to prevent, mitigate, or otherwise remedy conditions that existed prior to the establishment of the interconnection of the Facility with the EPE Transmission System at the Afton Switching Station, and that were required or should have been required in order to prevent, mitigate, or remedy such conditions regardless of, or that otherwise are unrelated to, such interconnection. To the extent that Generator has made payment to EPE for any such costs and expenses, EPE shall refund to Generator such sums, with interest at the Interest Rate calculated from the date Generator made such payment(s) to the date Generator receives the refund, within thirty (30) days of any determination as to the appropriate allocation of the costs for such modifications or upgrades.

5.4.10 Subject to the provisions of this section, EPE shall credit Generator against charges for transmission service under any Transmission Service Agreement in an amount equal to the cost paid by Generator, including tax gross-up payments made by Generator to EPE in accordance with Article 7.5, for the Interconnection System Upgrades, plus interest calculated at the FERC approved interest rate from the date Generator incurred costs associated with the construction, engineering and installation of the Interconnection System Upgrades (“Transmission Service Credits”); provided, however, that such credits shall not apply to service under any Transmission Service Agreement under which transmission service credits or payments are due for transmission service upgrades until the cost of such upgrades has been fully amortized through payments by the Generator. If the amount of any remaining unapplied Transmission

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Service Credits (including those held by Generator’s assignee) that exist five (5) years from the Effective Date is equal to or less than three (3) million dollars, EPE shall refund such remaining unapplied Transmission Service Credits to Generator within thirty (30) days after reaching such five (5) year period, and no further Transmission Service Credits will be due to Generator or any other Person. If the amount of any remaining unapplied Transmission Service Credits (including those held by Generator’s assignee) that exists five (5) years after the Effective Date is greater than three (3) million dollars, EPE shall continue to credit Generator against charges for transmission service under any Transmission Service Agreement until the date the remaining balance of such unapplied Transmission Service Credits is equal to three (3) million dollars. Within thirty (30) days of such date, EPE shall refund three (3) million dollars to Generator (not to exceed the remaining balance of the unapplied Transmission Service Credits), and no further Transmission Service Credits shall be due to Generator or any other Person. Generator may assign any portion of the Transmission Service Credits to any Person that purchases the Facility or that purchases power from the Facility. In the event of such assignment, EPE will credit the assignee against charges for transmission services provided to the assignee with respect to power purchased from the Facility, subject to the limitations set forth above. Such assigned Transmission Service Credits shall reduce the amount of Transmission Service Credits available to the Generator on a dollar for dollar basis. Without limiting the foregoing, Generator will receive Transmission Service Credits against the charges for transmission service that EPE has invoiced Generator for service with respect to the Facility under the existing Transmission Service Agreement (filed with the FERC on October 29, 2002 in FERC Docket No. ER03-93-000) from the date such transmission service commenced thereunder until the Effective Date; provided that within thirty (30) days after the Effective Date, the Parties shall reconcile the amount of Transmission Service Credits to be applied against the charges for transmission service with respect to the Facility during such period.

5.5 Subcontractors. Nothing in this Agreement shall prevent any Party from using the services of subcontractors as it deems appropriate; provided, however, each Party shall require such subcontractors to comply with the relevant terms and conditions of this Agreement. The creation of any subcontractor relationship shall not relieve the retaining Party of any of its obligations under this Agreement.

5.6 Rights of Access.

5.6.1 Prior to the assignment of a portion of the BLM 102630 R-O-W, by Generator to EPE in accordance with Article 5.2, Generator shall provide EPE access to the Interconnection System Upgrades and the portion of the EPE Interconnection Facilities located within the Facility property boundary to enable EPE to perform required operation and maintenance activities of these facilities in accordance with Good Utility Practice. Contemporaneous with the assignment of a portion of the BLM 102630 R-O-W, Generator grants EPE at no cost to EPE and the Operating Agent, as applicable, access, easements, or licenses upon, over, under, and across TRACTS 1 and 2 as delineated on Appendix F that are necessary for EPE and the Operating Agent, as applicable, and their Agents and subcontractors to design, procure, construct, install, test, operate, maintain and repair/replace the EPE Interconnection Facilities and the Interconnection System Upgrades in accordance with the terms of this Agreement. With respect to TRACT 2 both before and after the assignment of a portion of BLM 102630 R-O-W, EPE or Operating Agent shall exercise such access rights without notification of or supervision by

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Generator. With respect to TRACT 3 before the assignment of a portion of BLM 102630 R-O-W, EPE shall exercise such access rights without notification of or supervision by Generator, except for the area inside the Afton Switching Station, which area will be subject to the notification requirements in the Afton Generating Plant Operating Procedures. With respect to TRACT 1 both before and after the assignment of a portion of the BLM 102630 R-O-W EPE or Operating Agent shall exercise such access rights only with supervision by Generator. EPE or Operating Agent shall provide Generator reasonable notice under the circumstances of any request for such supervised access, and Generator and EPE shall mutually agree upon a date and time of such supervised access and such agreement shall not be unreasonably withheld or delayed. In addition to the aforementioned requirement, in exercising such supervised access rights, EPE and the Operating Agent, as applicable, shall (a) not unreasonably disrupt or interfere with normal operations of Generator’s business, (b) act in a manner consistent with Good Utility Practice, and (c) adhere to the safety rules and procedures established by Generator. Generator shall execute such documents as EPE and the Operating Agent, as applicable, may reasonably require to enable EPE or the Operating Agent, as applicable, to establish record evidence of such access rights. Such access rights shall remain in effect for so long as this Agreement is in effect.

5.6.2 Contemporaneous with the assignment of a portion of the BLM 102630 R-O-W by Generator to EPE in accordance with Article 5.2, EPE grants, at no cost to Generator, all access, easements or licenses upon, over, under and across TRACT 3 as delineated on Appendix F that are necessary for Generator and its Agents and subcontractors to design, procure, construct, install, test, operate, maintain and repair/replace Generator’s Interconnection Facilities, EPE Interconnection Facilities, and Facility, as applicable, in accordance with the terms of this Agreement. Such access rights for Generator’s facilities located inside the Afton Switching Station shall be exercised by Generator only with supervision by EPE or the Operating Agent, as applicable. Generator shall provide EPE or the Operating Agent, as applicable, reasonable notice under the circumstances of any request for such supervised access to the Afton Switching Station, and EPE or Operating Agent, as applicable, and Generator shall mutually agree upon the date and time of such supervised access, such agreement not to be unreasonably withheld or delayed. In addition to the aforementioned requirement, in exercising such access rights, Generator shall (a) not unreasonably disrupt or interfere with normal operations of EPE or the Operating Agent, (b) act in a manner consistent with Good Utility Practice, and (c) adhere to the safety rules and procedures established by the Operating Agent and EPE. EPE or the Operating Agent, as applicable, shall execute such documents as Generator may reasonably require to enable it to establish record evidence of such access rights. Such access rights shall remain in effect for so long as this Agreement is in effect.

5.6.3 Any Party or its subcontractors performing construction, or other work, on the property of the other Party shall be responsible for proper housekeeping during the period the work is being performed and proper clean-up of the property in a timely fashion after the work is completed.

5.7 Course and Completion of Construction.

5.7.1 Generator shall promptly notify EPE in writing when the construction of Generator’s Interconnection Facilities and the EPE Interconnection Facilities is complete. Likewise, each

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Party shall promptly notify the other Party in writing when the construction of the Interconnection System Upgrades is complete.

5.7.2 Generator shall keep the Generator’s Interconnection Facilities, the EPE Interconnection Facilities, Interconnection System Upgrades, and any real or personal property of EPE related to this interconnection project free and clear of all Generator, contractor, subcontractor, supplier or materialmen’s liens, claims and encumbrances arising out of the construction of the Generator’s Interconnection Facilities, the EPE Interconnection Facilities and Interconnection System Upgrades. Generator shall provide to EPE lien waivers from Generator and all such contractors, subcontractors, suppliers or materialmen before or upon completion of the Generator’s Interconnection Facilities, the EPE Interconnection Facilities and Interconnection System Upgrades. In the event that any such lien arising out of the construction of the Generator’s Interconnection Facilities, the EPE Interconnection Facilities and Interconnection System Upgrades shall nevertheless be filed or asserted against the real or personal property of EPE, Generator agrees to take all steps necessary and proper for the release and discharge of such liens in the manner allowed under New Mexico law. Generator shall indemnify and hold EPE harmless against any and all loss, claims, or suits (including costs and attorneys’ fees), for any lien claims asserted or filed by any party on or against EPE’s real or personal property relating to the construction of Generator’s Interconnection Facilities, the EPE Interconnection Facilities and the Interconnection System Upgrades.

5.8 Timely Completion.

5.8.1 Generator shall use Commercially Reasonable Efforts to design, procure, construct, install, and test Generator’s Interconnection Facilities and EPE Interconnection Facilities in accordance with the schedule set forth in Appendix C, which schedule may be revised from time to time by mutual agreement of the Parties.

5.8.2 Each Party shall use Commercially Reasonable Efforts to design, procure, construct, install, and test the Interconnection System Upgrades, in accordance with the schedule set forth in Appendix C, which schedule may be revised from time to time by mutual agreement of the Parties. EPE shall, at Generator’s request and expense, take all appropriate actions to accelerate its work under this Agreement in order to meet the schedule set forth in Appendix C, provided that Generator authorizes such actions and the costs associated therewith in advance and pays such costs in accordance with the payment schedule mutually agreed upon by the Parties.

5.8.3 If any of the Interconnection System Upgrades is not reasonably expected to be completed prior to the Commercial Operation Date of the Facility, Generator may, at its option, have operating studies performed at its expense to determine the maximum allowable output of the Facility, based upon the portion of the Interconnection System Upgrades that is expected to be completed prior to such Commercial Operation Date and, subject to EPE’s standards and Good Utility Practice, Generator will be permitted to operate the Facility, provided such limited operation of the Facility does not adversely affect the safety and reliability of the EPE Transmission System.

5.9 Environmental Compliance and Procedures. The Parties shall comply with (a) all applicable Environmental Laws in meeting all their obligations under this Agreement; and (b) all local

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notification and response procedures required for all applicable environmental and safety matters which affect the ability of the Parties to meet their respective obligations under this Agreement.

5.10 Generator Modeling Data. Generator shall provide the Operating Agent and EPE with such final modeling data of the Facility and Interconnected Facilities that reflect final Facility unit data and settings of the generation protection and control equipment as is reasonably requested by the Operating Agent and EPE and is necessary for reliable operation of the EPE Transmission System, including (a) the turbine speed/load controls including the governor; and (b) the excitation system including the automatic voltage regulator, power system stabilizer, over-excitation controls and limits, and other controls and limits. Such modeling data is to be provided in the format of the computer programs utilized by the Operating Agent and EPE. On the Operation Date, such programs are: Powerflow-General Electric PSLF; Transient Stability-General Electric PSLF; Short Circuit-Aspen One Liner.

5.11 Equipment Requirements. All equipment shall be of utility grade that meets or exceeds the quality of the equipment as required by EPE. The trip energy source for the interconnection breaker shall be of a stored energy type (i.e., battery) that will be available under circumstances when the alternating current source is unavailable. Generator shall ensure that Generator’s Interconnection Facilities comply with all applicable requirements of the National Electrical Safety Code, as amended from time to time, and/or any Applicable Laws and Regulations.

5.12 Required Diagrams. Generator shall maintain the following equipment at locations approved by the Operating Agent, which approval shall not be unreasonably withheld or denied: (a) a permanent and weatherproof one-line electrical diagram of the Facility located at the Facility site; and (b) a permanent and weatherproof map of the Facility showing the location of all major equipment. EPE shall maintain, at locations approved by Generator, which approval shall not be unreasonably withheld or denied, a permanent and weatherproof one-line diagram of the EPE Interconnection Facilities.

5.13 Required Personnel Information. No later than fifteen (15) Business Days after the Effective Date, Generator shall provide the Operating Agent the names and current telephone numbers of at least two (2) persons who are authorized to provide access to the Facility and who have authority to make decisions regarding the Facility, Generator’s Interconnection Facilities, and Generator’s operations. Generator shall keep the names and telephone listings current at all times during the term of this Agreement.

5.14 Use of Afton Switching Station by Third Parties.

5.14.1 If required by Applicable Laws and Regulations, or if EPE in its sole discretion allows one or more third parties to use Afton Switching Station, or any part thereof, and such use decreases the capacity of Afton Switching Station available to the Facility, or otherwise causes any detriment to the Facility or to Generator, or benefits any party (including EPE) other than Generator, then Generator and such third party (parties) shall negotiate in good faith to determine the appropriate compensation due to Generator as a result of such third party use and to determine the appropriate allocation of the annual carrying charges. EPE shall include a provision comparable to this Article 5.14.1 in its agreements with third party users providing for

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such third party users to participate in such negotiations. In any case, the Generator shall only be entitled to receive a reduction in charges under this Agreement equal to the amount of charges allocated to the third party user(s) (with a corresponding reduction in credits against the cost of transmission service in accordance with Article 5.4.10). If the issue of such compensation or allocation cannot be resolved through such negotiations, it shall be submitted to the FERC for resolution.

5.14.2 If one or more third parties are to use Afton Switching Station in accordance with this Article 5.14 and the Operating Agent determines that, as a result, Good Utility Practice requires that modifications be made to the Interconnected Facilities, the Operating Agent must comply with notification and scheduling provisions of Article 5.15. In no event shall Generator be responsible for the costs of any such modifications.

5.14.3 If it is determined by the FERC or any Governmental Authority that any costs associated with the design, engineering, construction, procurement, or installation of any of the EPE Interconnection Facilities or Interconnection System Upgrades paid for by Generator pursuant to this Agreement are not Generator’s responsibility, EPE shall refund to Generator, no later than sixty (60) days after the determination by FERC or any Governmental Authority, that portion of the costs paid by Generator that are included in the transmission revenue requirement or were paid by Generator and that have not been reflected in credits, if any, against the cost of transmission service from the Facility, with interest at the Interest Rate.

5.15 Interconnected Facilities and Facility Additions, Modifications or Replacements.

5.15.1 EPE Interconnection Facilities and EPE Transmission System.

(a) Any additions to, modifications to, or replacements of the EPE Interconnection Facilities must be constructed and operated in accordance with Good Utility Practice. If such additions, modifications, or replacements made after the Operation Date will likely cause a material adverse effect on Generator’s operation of the Facility, the Operating Agent will, except in cases of Emergency, provide a minimum of thirty (30) days’ advance written notice to Generator prior to undertaking such additions, modifications, or replacements. In the written notice, the Operating Agent must advise Generator when such additions, modifications or replacements are expected to be made; the time period expected to be required to complete such additions, modifications or replacements; and whether, if known, such additions, modifications or replacements are expected to interrupt or curtail the flow of electricity from the Facility. The Parties shall mutually agree in advance upon a schedule for such additions, modifications or replacements, such agreement not to be unreasonably withheld or delayed.

(b) Unless required by Applicable Laws and Regulations, Generator shall not be responsible for the costs of any additions, modifications, or replacements made to the EPE Transmission System by EPE, in its sole

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discretion, after the Operation Date in order to facilitate (a) the interconnection of a third party or (b) the provision of transmission service to or for a third party. Generator shall, however, be responsible for all costs of any additions, modifications, or replacements made to the EPE Transmission System as a result of any additions, modifications, or replacements made by Generator to the Facility.

(c) If any additions, modifications, or replacements to the EPE Interconnection Facilities (other than those caused by additions, modifications, or replacements made by the Generator to the Facility) cause a material adverse effect on the Generator’s Interconnection Facilities or the interconnection of the Facility (via Generator’s Interconnection Facilities) to the EPE Transmission System at the Afton Switching Station, EPE shall be responsible, at its sole cost and expense, for all actions necessary to mitigate such effect on the interconnection (“Mitigation Actions”) and, if necessary, to promptly and expeditiously re-establish the connection of the Facility (via Generator’s Interconnection Facilities) with the EPE Transmission System at the Afton Switching Station, in accordance with Good Utility Practice and/or secure such services as are necessary to deliver the capacity and energy to the Interconnection Point in accordance with Good Utility Practice (“Reconnection Activities”); provided, however, that, if EPE is required by Applicable Laws and Regulations or the RTO (if applicable) to undertake such additions, modifications, or replacements, EPE shall not be required to undertake any Mitigation Action or Reconnection Activity.

5.15.2 Generator’s Interconnection Facilities and Facility. Except for changes deemed by the Operating Agent to be necessary to ensure the protection and safety of a Party’s personnel and the safety and reliability of a Party’s property, Generator shall not be required to make any modifications to the Facility or Generator’s Interconnection Facilities unless such change is consistent with Good Utility Practice and required (i) as a result of a change in the Facility or (ii) as a result of a change on the EPE Transmission System which is required by Good Utility Practice. Generator shall not be responsible for the cost of any such modifications and the cost of operating and maintaining such modifications unless required by Applicable Laws and Regulations or such modifications are required as a result of a change in the Facility made by Generator.

Article VI

ACCEPTANCE AND PERFORMANCE TESTING

AND COMPLIANCE MONITORING

6.1 Responsibility for Testing.

6.1.1 Prior to the Operation Date, Generator shall perform all testing of the Facility and Generator’s Interconnection Facilities required by the RTO (if applicable), NERC and WSCC. EPE or the Operating Agent, as applicable, may require Generator to perform additional testing

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whenever EPE or the Operating Agent reasonably determines that such additional testing is required for reliability reasons. All testing shall be successfully completed before the Operation Date. Testing subsequent to the Operation Date shall be performed in compliance with the frequency requirements of NERC, WSCC, and the RTO (if applicable) and any other reliability requirements of any other organization/entity with responsibility for electricity and whose requirements Generator is obligated to follow. All such tests shall be performed to the specifications of NERC, WSCC, the RTO (if applicable), or any other specifications required by new or other reliability organizations with responsibility for electricity and whose requirements Generator is obligated to follow. Generator shall inform EPE or the Operating Agent, as applicable, in advance (whenever possible, a minimum of five (5) Business Days) when such tests are scheduled to occur, and EPE shall have the right to have representatives observe and monitor such tests. The cost of all such testing shall be borne by Generator.

6.1.2 Prior to the Operation Date, EPE or the Operating Agent, as applicable, shall perform all testing of the EPE Interconnection Facilities and the Interconnection System Upgrades required by NERC, WSCC and the RTO (if applicable). All testing shall be successfully completed before the Operation Date. After the Operation Date, the Operating Agent and EPE shall test their facilities at their own expense (or, in the case of the Operating Agent, the EPE Interconnection Facilities at the expense of EPE) in accordance with Good Utility Practice. Generator shall have the right, upon five (5) Business Days’ advance written notice to the Operating Agent or EPE to require additional testing of such entity’s facilities, at Generator’s expense, if Generator reasonably believes that such entity’s facilities are causing a material adverse effect on the operation of the Facility or Generator’s Interconnection Facilities, or as may be otherwise prudent in accordance with Good Utility Practice, and shall have the right to be present during such tests.

6.2 Responsibility for Modifications Following Testing. Based upon the pre-operational testing, Generator is responsible for making any modifications necessary to ensure the safe and reliable operation of Generator’s Interconnection Facilities and the EPE Interconnection Facilities in accordance with Good Utility Practice; EPE is responsible for making any modifications necessary to ensure the safe and reliable operation of the Interconnection System Upgrades in accordance with Good Utility Practice. The costs of all such modifications are to be borne by Generator, except to the extent the modifications are required as a result of the sole negligence or willful misconduct of EPE, or any Agent of EPE.

6.3 Documentation of Results to EPE or the Operating Agent. Generator shall provide EPE or the Operating Agent, as applicable, with necessary documentation of all test results for all tests performed pursuant to Article 6.1.1. The documentation shall be, at a minimum, that required to conform with any RTO, NERC or WSCC requirements.

6.4 Facility Certification. Generator shall comply with any facility certification requirements of NERC, WSCC, and the RTO (if applicable).

6.5 Transmission Service During Testing. Generator has sole responsibility to make necessary arrangements under the EPE OATT to procure any transmission service over the EPE Transmission System that may be required to accommodate the testing procedures of the Facility.

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6.6 EPE Inspection Rights. EPE (which, for the purposes of this Article 6.6, shall be deemed to include the Operating Agent) shall have the right, but shall have no obligation or responsibility, to: (a) observe Generator’s tests and/or inspection of any of Generator’s Protective Equipment; (b) review the settings of Generator’s Protective Equipment; and (c) review Generator’s maintenance records relative to the Generator’s Protective Equipment. EPE may exercise the foregoing rights from time to time as it deems necessary upon five (5) Business Days’ written notice to Generator. However, the exercise or non-exercise by EPE of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the Facility or Generator’s Protective Equipment or the operation thereof, nor as a warranty as to the fitness, safety, durability, or reliability of same.

6.7 Generator Inspection Rights. Generator, upon five (5) Business Days’ advance written notice to the Operating Agent has the right, but not the obligation, to inspect or observe the operation and maintenance activities, equipment tests, installation, construction, or other modifications to the EPE Interconnection Facilities which could cause a material adverse effect on Generator’s operations. However, the exercise or non-exercise by Generator of any of the foregoing rights of observation, review or inspection shall be construed neither as an endorsement or confirmation of any aspect, feature, element, or condition of the EPE Interconnection Facilities or the operation thereof, nor as a warranty as to the fitness, safety, durability, or reliability of same.

6.8 EPE’s Reviews, Inspections, and Approvals. EPE’s or Operating Agent’s review, inspection, and approval, related to the Generator’s Interconnection Facilities and EPE’s Interconnection Facilities required under this Agreement shall not be unreasonably withheld or delayed, and will be limited to the purpose of ensuring the safety, reliability, protection and control of the EPE Transmission System.

Article VII

INTERCONNECTION FACILITY COSTS AND BILLING

7.1 Interconnection Construction Completion and Cost.

7.1.1 Notification of Delay. If any event occurs that will materially affect the time for completion of the Interconnection System Upgrades, or the ability to complete them, the Party responsible for the construction of the affected portion of the Interconnection System Upgrades shall, within five (5) Business Days of its knowledge of any such event, notify the other Party . In such circumstances, the responsible Party shall, within ten (10) Business Days of notifying the other Party of such an event and corresponding delay, convene a technical meeting with the other Party to evaluate the alternatives available to the other Party. The responsible Party also shall make available to the other Party all studies and work papers related to the event and corresponding delay, including all information that is in the responsible Party’s possession that is reasonably needed by the other Party to evaluate alternatives.

7.1.2 Cost Estimate. Pursuant to Article 5.4.5 and delineated in Exhibit B and subject to audit by EPE pursuant to Article 7.1.3 below, the Parties have established the cost to design,

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engineer, procure equipment, and construct the Interconnection System Upgrades and the EPE Interconnection Facilities.

7.1.3 Audit of Cost. Each Party shall have the right to receive such cost information as is reasonably necessary to verify the cost of the Interconnection System Upgrades and the EPE Interconnection Facilities constructed by the other Party and that such cost was incurred in accordance with Good Utility Practice. EPE shall have the right to receive such cost information as is reasonably necessary to verify the cost of Generator’s activities associated with the Interconnection System Upgrades and the EPE Interconnection Facilities and that such costs were incurred in accordance with Good Utility Practice. Each Party shall have the right to audit (a) the other Party’s accounts and records pertaining to the Interconnection System Upgrades and the EPE Interconnection Facilities, at the offices where such accounts and records are maintained, provided at least seven (7) Business Days’ notice is given prior to any audit, and provided further that the audit shall be limited to those portions of such accounts and records that relate to services provided under this Agreement. Costs incurred or billed pursuant to this Agreement for the design, engineering, procurement of equipment, and construction of the Interconnection System Upgrades and the EPE Interconnection Facilities, and the review and approval of the EPE Interconnection Facilities shall be subject to audit for a period of one (1) year following the issuance of a final cost invoice (in the case of costs billed by EPE), or a final statement of costs incurred (in the case of costs incurred by Generator), in accordance with Article 7.2.2. All other costs incurred or billed pursuant to this Agreement shall be subject to audit for a period of one (1) year after the date the bill was rendered. Generator and EPE shall keep records and data related to all costs billed or incurred under this Agreement for a period equivalent to the audit periods described in this Article 7.1.3. As a result of the audit, adjustments may be made to the costs established in Exhibit B for the EPE Interconnection Facilities and the Interconnection System Upgrades so that the final audited costs match the costs established in Exhibit B. It shall be the Operating Committee responsibility to reconcile the final audited costs with the costs established in Exhibit B.

7.2 Invoices and Payments.

7.2.1 Monthly Statements.

(a) EPE shall render to Generator monthly statements for EPE’s costs for review and approval activities for the EPE Interconnection Facilities, and EPE’s costs for the Interconnection System Upgrades on the EPE Transmission System by certified mail, facsimile or other acceptable means conforming to the provisions of Article 30.9. Such statements shall set forth in reasonable detail any costs incurred by or on behalf of EPE or other charges or amounts payable by Generator under the terms of this Agreement for the period covered thereby in connection with the EPE Interconnection Facilities and Interconnection System Upgrades. Generator shall make payment of the amount shown to be due to EPE by wire transfer to an account specified by EPE not later than the thirtieth (30th) day after receipt of the statement, unless such day is not a Business Day, in which case Generator shall make payment on the next Business Day. All such payments shall be deemed to be made when

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said wire transfer is received by EPE. Overdue payments shall accrue interest daily at the then-current Interest Rate from the due date of such unpaid amount until the date paid.

(b) Consistent with Articles 5.4.3 and 13.1, EPE is responsible for the maintenance, repair, and replacement of the EPE Interconnection Facilities following installation. Generator is responsible for all costs incurred by EPE for such activities. EPE, as required, shall invoice Generator for any EPE incurred costs associated with any maintenance, repair, and replacement of the EPE Interconnection Facilities. Such invoice shall provide Generator with reasonable detail of the actual costs incurred by EPE. Generator shall make payment of the amount shown to be due to EPE by wire transfer to an account specified by EPE not later than the thirtieth (30th) day after receipt of the statement, unless such day is not a Business Day, in which case Generator shall make payment on the next Business Day. All such payments shall be deemed to be made when said wire transfer is received by EPE. Overdue payments shall accrue interest daily at the then-current Interest Rate from the due date of such unpaid amount until the date paid.

7.2.2 Invoice/Statement of Final Cost.

(a) Within nine (9) months after the Effective Date, EPE shall provide an invoice of the final costs associated with EPE’s review and approval of the EPE Interconnection Facilities and final costs of the Interconnection System Upgrades and the net amount due, if any, from Generator allowing for any payments made by Generator pursuant to this Agreement. The final cost invoice shall set forth in reasonable detail the actual costs incurred by or on behalf of EPE in reviewing, approving, designing, procuring, constructing, installing and testing the EPE Interconnection Facilities, and the Interconnection System Upgrades, and shall set forth such costs in sufficient detail to enable Generator to compare the actual costs with the estimates and to ascertain deviations, if any, from the cost estimates. Generator shall reimburse EPE for the amount of such invoice within thirty (30) days after receipt of such invoice, unless such day is not a Business Day, in which case Generator shall make payment on the next Business Day. To the extent that the estimated costs for the Interconnection System Upgrades already paid by Generator exceed the final, actual costs that Generator is obligated to pay hereunder for the Interconnection System Upgrades, EPE shall refund to Generator an amount equal to the difference within thirty (30) days of the issuance of the invoice of the final cost.

(b) Within nine (9) months after the Effective Date, Generator shall provide a statement of the final costs it incurred for the EPE Interconnection Facilities and the Interconnection System Upgrades. The final statement shall set forth in reasonable detail the actual costs incurred by or on

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behalf of Generator in designing, procuring, constructing, installing and testing the EPE Interconnection Facilities and the Interconnection System Upgrades.

7.2.3 Failure of Payment. In the event Generator fails, for any reason other than a billing dispute as described below, to make payment to EPE on or before the due date as described in Article 7.2.1(a) above, an event of breach by Generator shall be deemed to exist under Article 22.2(a). In the event of a billing dispute between EPE and Generator, EPE shall continue to perform its responsibilities under this Agreement and Generator shall not be deemed to have committed an event of breach under Article 22.2(a), as long as Generator (a) continues to make all payments not in dispute, and (b) upon request of EPE, pays into an independent escrow account the portion of the invoice in dispute, pending resolution of such dispute.

7.2.4 Billing Disputes.

(a) Generator may, in good faith, challenge the correctness of any bill rendered under this Agreement for the design, engineering, procurement, and construction of the Interconnection System Upgrades and for the review and approval of the EPE Interconnection Facilities no later than one (1) year following the issuance of a final cost invoice in accordance with Article 7.2.2(a). Generator may, in good faith, challenge the correctness of any other bill rendered under this Agreement no later than one (1) year after the date the bill was rendered. In the event that Generator challenges a bill or a portion prior to date on which payment is due for such bill, Generator shall nonetheless pay the portion of the bill that is not disputed when due, with notice given to the entity that rendered the bill at that time. Any challenge to a bill shall be in writing and shall state the specific basis for such challenge. If it is subsequently agreed or determined under Article XXIX that an adjustment is appropriate, such adjustment shall be made in accordance with Article 7.3.

(b) EPE may, in good faith, challenge the correctness of any statement rendered by the Generator under this Agreement for the costs incurred in connection with the design, engineering, procurement, and construction of the EPE Interconnection Facilities and the Interconnection System Upgrades no later than one (1) year following the issuance of a final cost statement in accordance with Article 7.2.2(b). If it is subsequently agreed or determined under Article XXIX that an adjustment is appropriate, such adjustment shall be made to the final statement of costs incurred prepared by the Generator in accordance with Article 7.2.2(b).

(c) Generator may, in good faith, challenge the correctness of any bill rendered pursuant to Article 7.2.1 (b) no later than one (1) year following the issuance of any monthly bill. In the event that Generator challenges a bill or a portion prior to the date on which payment is due

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for such bill, Generator shall nonetheless pay the portion of the bill that is not disputed when due, with notice given to the entity that rendered the bill at that time. Any challenge to a bill shall be in writing and shall state the specific basis for such challenge. If it is subsequently agreed or determined under Article XXIX that an adjustment is appropriate, such adjustment shall be made in accordance with Article 7.3.

7.3 Adjustments. In the event adjustments or corrections to monthly statements rendered by EPE under Article 7.2.1 are required as a result of errors in computation or billing, the entity that rendered the monthly statement shall promptly recompute amounts due hereunder and otherwise correct any errors in such statements. If the total amount, as recomputed, due from Generator is less than the total amount due as previously computed, and payment of the previously computed amount has been made to EPE, EPE shall pay the difference to Generator within thirty (30) days after correction of the erroneous invoice(s), together with interest at the Interest Rate. If the total amount, as recomputed, due from Generator is more than the total amount due as previously computed, and payment of the previously computed amount has been made to EPE, EPE shall invoice the difference to Generator according to the terms of Article 7.2; provided, however, that no adjustment for any statement or payment will be made unless objection to the accuracy thereof was made within the time frames described in Article 7.2.4; and provided further that this Article 7.3 will survive any termination of the Agreement for a period of one (1) year from the date of such termination for the purpose of such statement and payment objections.

7.4 Payment Not a Waiver. Payment of invoices by Generator shall not constitute a waiver of any rights or claims Generator may have under this Agreement.

7.5 Income Taxes. The costs associated with the Interconnection System Upgrades were incurred by Generator and pursuant to Article 5.4.10, Generator is entitled to Transmission Service Credits equal to those costs. Pursuant to Article 5.4.4, Interconnection System Upgrades are owned by EPE. As such, the Interconnection System Upgrades are part of the EPE Transmission System.

In the event the Internal Revenue Service (“IRS”) assesses income taxes against EPE as a result of this transaction pursuant to the terms and conditions of this Agreement (“ITCC Tax”), then Generator shall be solely responsible for and shall indemnify and hold EPE harmless from any such ITCC Tax and any penalties and interest assessed by the IRS relating to the ITCC Tax. Generator shall pay EPE such ITCC Tax, penalties and interest upon demand after receipt of written evidence of the assessment of such taxes. In the event Generator is required to pay the ITCC Tax, Generator shall be entitled to Transmission Service Credits equal to the amount of the ITCC Tax, penalties and interest actually paid plus any interest accrued thereon. For purposes of this Article 7.5, Generator’s liability for ITCC Tax shall be calculated on a fully grossed-up basis by taking into account EPE’s Federal and state composite tax rate at the time of the payments or property transfers based on the highest marginal tax rates then in effect (the “Composite Tax Rate”), less the present value (based on a discount rate of 8%) of the product obtained by multiplying (i) the annual tax depreciation deductions to which EPE would be entitled over the life of the Interconnection System Upgrades by (ii) the Composite Tax Rate.

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In the event the IRS assesses ITCC Tax against EPE, and Generator pays such tax to EPE in accordance with the preceding paragraph, Generator shall have the right and option to request that EPE appeal that portion of EPE’s tax assessment relating to the ITCC Tax through the appropriate administrative and judicial process. Generator agrees to notify EPE whether Generator elects to appeal the tax assessment within thirty (30) days after being notified of the tax assessment; provided, however, that in no event shall Generator’s notice be provided to EPE less than ten (10) days before the date that EPE is required to perfect such appeal. Generator’s failure to give notice to EPE within such time limits shall be deemed to be an election by Generator not to appeal the tax assessment. Any such appeal shall be at Generator’s sole cost and expense. EPE agrees to provide reasonable assistance in such appeal. If, through the appellate process, it is conclusively determined that EPE is not liable for the ITCC Tax for the tax years at issue, EPE shall promptly refund to Generator any amounts paid by Generator to EPE pursuant to this Article 7.5 for such tax years (with a corresponding reduction in credits to be applied to Generator’s Transmission Service Credits), with respect to any payment which is determined to be non-taxable taking into consideration a proportionate allocation of EPE’s depreciation deductions. If the amount to be refunded to Generator in accordance with the immediately preceding sentence is greater than the remaining balance of Transmission Service Credits (including the amounts relating to the ITCC Tax paid by Generator to EPE), then the amount which EPE shall be required to refund to Generator shall be reduced to equal the remaining balance of Transmission Service Credits, which shall be reduced to zero following such refund.

For purposes of this Article 7.5, all references to the IRS shall include applicable state income taxing authorities with jurisdiction over EPE.

Article VIII

OPERATIONS

8.1 General. With respect to their performance under this Agreement, the Operating Agent, EPE, and Generator shall comply with all applicable manuals, standards, and guidelines of NERC, WSCC, RTO (if applicable), or any successor agency.

8.2 Obligations of Operating Agent. Operating Agent shall operate and control the EPE Interconnection Facilities, (a) in a safe and reliable manner, (b) in accordance with Good Utility Practice, and (c) in accordance with the terms and conditions of this Agreement. In the event of any conflict between the terms and conditions of this Agreement and applicable planning, operational, and/or reliability criteria, protocols, and directives of the RTO (if applicable), NERC and WSCC, the applicable planning, operational, and/or reliability criteria, protocols, and directives of the RTO (if applicable), NERC and WSCC shall govern.

8.3 Obligations of Generator.

8.3.1 Synchronization. Generator shall assume all responsibility and cost for properly synchronizing the Facility for operation with the EPE Transmission System. Synchronizing of generation will be coordinated with the Operating Agent’s SOCC.

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8.3.2 Operation and Control. Generator shall operate and control the Facility and Generator’s Interconnection Facilities (a) in a safe and reliable manner, (b) in accordance with Good Utility Practice, and (c) in accordance with the terms and conditions of this Agreement. In the event of any conflict between the terms and conditions of this Agreement and applicable planning, operational, and/or reliability criteria, protocols, and directives of the RTO (if applicable), NERC and WSCC, the applicable planning, operational, and/or reliability criteria, protocols, and directives of the RTO (if applicable), NERC and WSCC shall govern.

8.3.3 Control Area Requirements. Nothing in this Agreement should be construed as creating any obligation that Generator operate the Facility as part of the EPE Control Area. If the Facility is not operated as part of the EPE Control Area, in no event shall this Agreement prohibit, prevent, or otherwise limit the ability of Generator to operate the Facility in accordance with the requirements of the control area of which it is part, and the Parties shall negotiate in good faith to amend this Agreement as necessary or appropriate.

8.4 Reliability Criteria.

8.4.1 Power System Stabilizers (PSS). Generator shall install and operate PSS on generators in accordance with the WSCC criteria, the RMS criteria and any other requirement that the Operating Agent is obligated to follow.

8.4.2 Automatic Voltage Regulation (AVR). Generator shall install and operate AVR in accordance with all requirements of WSCC, the RMS criteria and any other requirement that the Operating Agent is obligated to follow. Each interconnected unit shall have AVR and such AVR shall be tuned in accordance with Institute of Electronics and Electrical Engineers (“IEEE”) standard 421 or its successor. Voltage regulator controls and limit functions (such as over- and under-excitation and volts/hertz limiters) shall coordinate with the Facility’s generator’s short duration capabilities and protective relays. AVRs must be continuously acting solid state analog or digital. Tuning shall be in accordance with the WSCC criteria and standards. Tuning results shall be included in commissioning test reports provided to the Operating Agent or EPE, as applicable.

8.4.3 Governors. Generator shall operate all governors in accordance with requirements of NERC and the WSCC, including any requirements for Governor Droop settings. To provide equitable and coordinated system response to load/generation imbalances, governors shall not be blocked or operated with excessive dead-bands.

8.5 Quality of Power. Generator shall ensure that the Facility’s quality of power at the Interconnected Facilities adheres to the standards set by NERC, WSCC, the RTO (if applicable) and the American National Standards Institute (“ANSI”). In turn, the Operating Agent shall ensure that quality of power at the Interconnected Facilities adheres to the standards set by NERC, WSCC, the RTO (if applicable) and ANSI. To the extent that the Operating Agent determines that the Afton Switching Station is adversely affected by flicker or harmonic distortion caused by Generator, or EPE determines that the EPE Transmission System is adversely affected by flicker or harmonic distortion caused by Generator, Generator shall take the necessary actions to resolve the problem promptly upon notice from the Operating Agent or EPE. If such actions taken by Generator do not resolve the problem, the Operating Agent shall

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notify Generator of the continuing problem and may curtail, interrupt or reduce deliveries of electricity, or disconnect the Facility from the EPE Transmission System at the Afton Switching Station, in accordance with Good Utility Practice until the problem is resolved to the satisfaction of the Operating Agent or EPE, as the case may be.

8.6 Protection and System Quality.

8.6.1 Facilities. Generator shall, at its expense, install, maintain, and operate Protective Equipment at the Facility, including such protective and regulating devices as are required by the RTO (if applicable), NERC, WSCC, or by order, rule or regulation of any Governmental Authority or as are otherwise necessary to protect personnel and equipment and to minimize adverse effects to the Afton Switching Station and EPE’s electric system arising from the Facility.

8.6.2 Protective Equipment. Generator agrees that Protective Equipment must be installed to:

(a) ensure safety of the general public, and personnel of EPE (including in its capacity as Operating Agent), and Generator;

(b) minimize damage to the Afton Switching Station property and to the property of the general public, EPE and its customers;

(c) minimize adverse operating conditions on the EPE Transmission System; and

(d) permit Generator to operate the Facility in parallel with the EPE Transmission System in a safe and efficient manner.

The necessary Protective Equipment will be installed in accordance with Articles 5.3.2 and 5.4.

8.7 Adjustments. The Operating Agent may require Generator to adjust the real power output or reactive power from the Facility only for purposes of Emergency or Abnormal Conditions. The Operating Agent may not, unless the Generator and Operating Agent agree in writing, require Generator to make such adjustments based on economic considerations.

8.8 Switching and Tagging Procedures.

8.8.1 Compliance with Procedures. The Parties shall abide by the Operating Agent’s switching and tagging rules as the Operating Agent may modify them from time to time with respect to activities at the Interconnected Facilities and the Afton Switching Station, and mutually agreed to activities within the Facility. The Operating Agent shall notify Generator in advance of the Operating Agent’s switching and tagging rules and any amendments thereto. Generator shall ensure its personnel are trained and knowledgeable regarding the Operating Agent’s switching and tagging rules and grounding and isolation procedures.

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8.8.2 Reclosing. Generator acknowledges that following an electric disturbance, certain equipment at the Afton Switching Station may reclose in accordance with Good Utility Practice. The Operating Agent will provide Generator notice, as far in advance of implementation as is reasonably practical, of the reclosing practices of the EPE Interconnection Facilities and the Interconnection System Upgrades, including the Afton Switching Station. The Operating Agent shall provide Generator all data needed to study the effect of proposed changes to such reclosing practices and allow a reasonable time period, not to exceed 120 calendar days, for modification of Generator’s Protective Equipment if necessary. To the extent practicable, Operating Agent will cooperate with Generator to establish or modify the reclosing angle settings of the Operating Agent’s reclosing operations to minimize the impact such operations will have on the EPE Transmission System (including the Afton Switching Station) and the Facility.

Generator shall have sole responsibility for protecting the Facility, Generator’s Interconnection Facilities and related equipment from any damage resulting from such reclosure. To the extent not prohibited by Applicable Laws and Regulations, Generator hereby indemnifies and agrees to hold harmless EPE, the Operating Agent, and their Agents for, against and from any and all losses, damages, costs and expenses caused by, resulting from or arising out of (a) any damage to the Facility, Generator’s Interconnection Facilities or related equipment to the extent caused by, resulting from, or arising out of any such reclosure and (b) death of or injury to any person to the extent caused by, resulting from, or arising out of any impact or effect of such reclosure upon the Facility, Generator’s Interconnection Facilities, and/or any related equipment.

If, for any reason, the Facility is disconnected from the EPE Transmission System at the Afton Switching Station (by electric disturbance, line switching, or otherwise), Operating Agent shall cause the switching device connecting the Facility to the EPE Transmission System at the Afton Switching Station to become and remain open and not reclose until the Operating Agent approves the reclosure.

8.9 General Orders. Each Party shall comply with the Operating Agent’s General Orders, in existence on the Effective Date and as may be modified from time to time, in the operation of the Interconnected Facilities and the Facility. The Operating Agent shall provide a written copy of its General Orders upon request of Generator and thereafter notify Generator of any modifications in the Operating Agent’s General Orders at least ten (10) days prior to the effective date of any such modifications.

8.10 Generation Alert. The Operating Agent shall issue generation alerts when it determines that the loss of a generating unit may create a system disturbance. When advised by the Operating Agent, Generator shall exercise Due Diligence to suspend non-essential maintenance and operational activities that could lead to the loss of the Facility during the alerts.

Article IX

RELIABILITY MANAGEMENT SYSTEM

9.1 Purpose. In order to maintain the reliable operation of the transmission grid, the WSCC Reliability Criteria Agreement sets forth reliability criteria adopted by the WSCC with which Generator and EPE shall comply.

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9.2 Compliance. Generator shall comply with the requirements of the WSCC Reliability Criteria Agreement, including the applicable WSCC reliability criteria set forth in Section IV of Annex A thereof, and, in the event of failure to comply, agrees to be subject to the sanctions applicable to such failure. Such sanctions shall be assessed pursuant to the procedures contained in the WSCC Reliability Criteria Agreement.

9.3 Participant Status. Each of the pertinent provisions of the WSCC Reliability Criteria Agreement is hereby incorporated by reference into this Article IX as though fully set forth herein, and Generator shall for all purposes be considered a “Participant,” as defined in the WSCC Reliability Agreement, and shall be entitled to all of the rights and privileges and subject to all of the obligations of a Participant under and in connection with the WSCC Reliability Criteria Agreement, including the rights, privileges, and obligations set forth in Sections 5, 6, and 10 of the WSCC Reliability Criteria Agreement.

9.4 Payment of Sanctions. Generator shall be responsible for reimbursing EPE for any monetary sanctions assessed against EPE, to the extent determined to be attributable to the action or inaction of Generator, by WSCC pursuant to the WSCC Reliability Criteria Agreement. Generator shall also be responsible for payment of any monetary sanction assessed against Generator by WSCC pursuant to the WSCC Reliability Criteria Agreement.

9.5 Transfer of Control or Sale of Facility. In any sale or transfer of control of the Facility or any portion thereof, Generator shall, as a condition of such sale or transfer of control, require the acquiring party or transferee with respect to the transferred Facility either to assume the obligations of the Generator with respect to this Agreement or to enter into an agreement with EPE imposing on the acquiring party or transferee the same obligations applicable to Generator pursuant to this Article IX.

9.6 Failure to Comply with RMS. In the event Generator fails to comply with the requirements of the WSCC Reliability Criteria Agreement incorporated herein and, in the opinion of EPE, endangers the safety or reliability of the EPE Transmission System, EPE shall have the right, subject to any necessary regulatory approval, to direct the Operating Agent to disconnect the Facility from the EPE Transmission System at the Afton Switching Station, and EPE and the Operating Agent shall have no liability for any damages incurred by Generator or the Facility as a result of such disconnection. Prior to any proposed disconnection, the Operating Committee shall meet and the Operating Agent shall advise the members of the Operating Committee regarding the reasons for the proposed disconnection.

9.7 Publication. Generator consents to the release by the WSCC of information related to Generator’s compliance with this Agreement only in accordance with the WSCC Reliability Criteria Agreement.

9.8 Third Parties. Except for the rights and obligations between the WSCC and Generator specified in this Article IX, this Article IX creates contractual rights and obligations solely between the Parties. Nothing in this Article IX shall create, as between the Parties or with respect to the WSCC: (a) any obligation or liability whatsoever (other than as expressly provided in this Article IX) or (b) any duty or standard of care whatsoever. In addition, nothing in this Article IX shall create any duty, liability, or standard of care whatsoever as to any other party. Except

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for the rights, as a third-party beneficiary under this Article IX of the WSCC against Generator, no third party shall have any rights whatsoever with respect to enforcement of any provision of this Article IX. The Parties expressly intend that the WSCC is a third-party beneficiary to this Article IX and the WSCC shall have the right to seek to enforce against Generator any provision of this Article IX, provided that specific performance shall be the sole remedy available to the WSCC pursuant to Article IX and Generator shall not be liable to the WSCC pursuant to this Article IX for damages of any kind whatsoever (other than the payment of sanctions to the WSCC, if so construed), whether direct, compensatory, special, indirect, consequential, or punitive.

9.9 Reserved Rights. Nothing in the RMS or the WSCC Reliability Criteria Agreement shall limit the right of EPE, subject to any necessary regulatory approvals, to take such other actions to maintain reliability, subject to any necessary regulatory approval, including disconnection, which EPE may otherwise be entitled to take.

9.10 Termination. The Generator may terminate its obligations pursuant to this Article IX: (a) if after the effective date of this Agreement, the requirements of the WSCC Reliability Criteria Agreement applicable to Generator are amended so as to adversely affect the Generator, provided that Generator gives fifteen (15) days’ notice of such termination to EPE and the WSCC within forty-five (45) days of the date of issuance of a FERC order accepting such amendment for filing, provided further that the forty-five (45) day period within which notice of termination is required may be extended by the Generator for an additional forty-five (45) days if the Generator gives written notice to EPE of such requested extension within the initial forty-five (45) day period; or (b) for any reason on one (1) year’s written notice to EPE and the WSCC.

9.11 Mutual Agreement. This Article IX may be terminated at any time by mutual agreement of Generator and EPE.

9.12 Severability. If one or more provisions of this Article IX shall be invalid, illegal or unenforceable in any respect, it shall be given effect to the extent permitted by Applicable Laws and Regulations, and such invalidity, illegality or unenforceability shall not affect the validity of the other provisions of this Article IX.

Article X

REACTIVE POWER

10.1 Obligation to Supply Reactive Power. Generator shall supply reactive power to the transmission grid in accordance with Good Utility Practice, and shall respond to requests from the Operating Agent to increase or decrease generator output voltage in a manner consistent with Generator’s obligation to operate the Facility, provided such requests are consistent with Good Utility Practice and are made in order to maintain reactive area support. The Facility shall operate in accordance with the reactive power requirements as set forth in this Agreement; provided, however, that such amount shall not exceed the amount available from the Facility’s equipment in service.

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10.2 Compensation. The Operating Agent shall compensate Generator for generating or absorbing reactive power at the specific request of the Operating Agent outside the power factor design limitation minimum requirement specified in Article 10.3.1. The Operating Agent shall also compensate Generator for start-up costs and real power costs if reactive support is requested by the Operating Agent when the Facility is off-line. Such compensation shall be in accordance with any applicable FERC tariff or rate schedule filed by Generator and accepted for filing by FERC. The Operating Agent and EPE reserve the right to oppose any tariff or rate schedule filed by Generator with FERC.

10.3 Reactive Power Standards.

10.3.1 Composite Power Delivery. The Facility power factor design limitation minimum requirement shall be a reactive power capability sufficient to provide a composite power delivery at the Interconnection Point at a power factor between 95% lagging and 95% leading. Under normal real-time operating conditions, Generator shall operate the Facility to maintain a voltage schedule at the Interconnection Point as prescribed by the Operating Agent within the Facility’s power factor design limitation minimum requirement, provided such schedule is consistent with Good Utility Practice, and necessary to maintain reactive support on the transmission grid. In the event that the voltage schedule at the Interconnection Point cannot be or is not maintained within such requirement, the Operating Agent may request that the Facility be operated (within the design limitations of the equipment in service at that time) up to the maximum available reactive power output (measured in mega-volt ampere reactance (“MVAR”)) in order to achieve the prescribed voltage schedule; provided, however, that the Operating Agent has equitably coordinated such requests with other generating facilities and other reactive power compensation resources in the affected area in order to achieve the prescribed voltage schedule. Generator shall promptly comply with all such requests made by the Operating Agent and shall be compensated as provided for in Article 10.2.

10.3.2 Compliance. In the event that under normal transmission system operating conditions, the Facility is unable to consistently maintain a reactive power capability within the power factor design limitation minimum requirement, Generator shall take appropriate actions to comply with such standards, including, if necessary, the installation of static and/or dynamic reactive power compensating devices.

10.3.3 Records. Records of requests made to Generator by the Operating Agent, and records indicating actual responses to such requests, shall be maintained by the Operating Agent and subject to a third party independent audit at Generator’s request and expense. Any request for an audit by Generator shall be made in accordance with Article 7.1.3.

10.4 Failure to Supply Reactive Power. To the extent that Generator fails to operate the Facility in accordance with this Article X and Generator has not taken any action pursuant to Article 10.3.2, the Operating Agent may, after three (3) days’ notice to Generator, take any necessary actions to remedy Generator’s default, at Generator’s expense, including requiring the installation of capacitor banks or other reactive compensation equipment required to ensure the proper voltage or reactive power supply at the Facility.

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Article XI

OUTAGES, INTERRUPTIONS, AND DISCONNECTIONS

11.1 Outage Scheduling. On or before January 1st of each year, or such other date mutually acceptable to the Operating Agent and Generator, each of the foregoing shall, subject to Article 3.7, provide to the other a non-binding preliminary maintenance schedule for the upcoming calendar year for the EPE Interconnection Facilities and Facility. The Operating Agent and Generator shall, subject to Article 3.7, each provide the other with timely non-binding updates to such schedules to reflect any significant changes.

11.2 Scheduled Maintenance and Coordination. To the extent practicable, the Operating Agent shall schedule any testing, shutdown, or withdrawal of the EPE Interconnection Facilities to coincide with Generator’s scheduled outages or, if not possible, during times acceptable to the Generator. The Operating Agent shall, subject to Article 3.7, notify Generator in advance of any such testing, shutdown, or withdrawal of facilities and the schedule for maintenance as well as any changes in the schedule. The Operating Agent shall restore the EPE Interconnection Facilities to service as quickly as possible in accordance with Good Utility Practice.

11.3 Other Maintenance and Coordination. To the extent that Generator desires EPE or the Operating Agent to perform maintenance during a time period other than a scheduled outage, EPE and the Operating Agent shall, subject to the EPE OATT, use Commercially Reasonable Efforts to meet Generator’s request; provided, however, that such maintenance will not have a material adverse economic impact upon EPE or the customers of the EPE Transmission System. If EPE determines, in the exercise of its reasonable judgment, that Generator’s request would have a material adverse economic impact upon EPE or the customers of the EPE Transmission System, but Generator is willing to reimburse EPE for any costs incurred by it, EPE shall use Commercially Reasonable Efforts to comply with Generator’s request.

11.4 Unplanned Outages. In the event of an unplanned outage of a Party’s facility (including the Facility) that adversely affects the other Party’s facilities, the Party that owns or controls the facility that is out of service shall use Commercially Reasonable Efforts to promptly restore that facility to service in accordance with Good Utility Practice and, subject to Article 3.7, to promptly notify the other Party as to the expected duration of the unplanned outage and, to the extent known, the reason therefor.

11.5 Disconnection.

11.5.1 Disconnection during Underfrequency Load Shed Event. The Parties shall at all times comply with NERC, WSCC, and RTO (if applicable) requirements. NERC planning criteria require the interconnected WSCC Grid frequency be maintained between 59.95 Hz and 60.05 Hz. WSCC has an off-nominal frequency program to which the EPE Transmission System adheres and all generators must also comply. In the event of an underfrequency system disturbance, the EPE Transmission System is designed to automatically activate a multi-tiered load shed program. Generator shall coordinate underfrequency relay set points for the Facility as determined by the Operating Committee, consistent with WSCC criteria.

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11.5.2 Disconnection after Agreement Terminates. Upon termination of this Agreement, the Operating Agent shall disconnect the Facility from the EPE Transmission System at the Afton Switching Station in accordance with the disconnection plan adopted pursuant to Article 23.4.

11.6 Continuity of Service. Notwithstanding any other provision of this Agreement, the Operating Agent shall not be obligated to accept, and the Operating Agent may require Generator to curtail, interrupt or reduce, delivery of energy if such delivery of energy impairs EPE’s ability to construct, install, repair, replace or remove any of its equipment or any part of its system in a safe and reliable manner or if the Operating Agent determines that curtailment, interruption or reduction is necessary to prevent, mitigate, or remedy an Emergency or for any reason otherwise permitted by Applicable Laws and Regulations. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such curtailments, interruptions, or reductions with respect to maintenance, investigation or inspection of any of EPE’s equipment or system consistent with the terms and conditions of this Agreement. Except in case of Emergency, in order not to interfere unreasonably with Generator’s operations, the Operating Agent shall give Generator reasonable prior notice of any proposed curtailment, interruption or reduction, the reason(s) for its occurrence, and, if it is known, its expected duration. With respect to any curtailment, interruption or reduction permitted under this Article 11.6, the Operating Agent agrees that: (a) the curtailment, interruption, or reduction shall continue only for so long as reasonably necessary under Good Utility Practice; (b) when the curtailment, interruption, or reduction must be made under circumstances which do not allow for advance notice, the Operating Agent will notify Generator by telephone as soon as practicable of the reasons for the curtailment, interruption, or reduction and, if known, its expected duration; and (c) Operating Agent will compensate Generator, except for reductions, interruptions or curtailments under the applicable OATT, pursuant to mutually agreed terms or pursuant to any applicable FERC-accepted tariff or rate schedule filed by Generator.

Article XII

EMERGENCY AND ABNORMAL CONDITION PROCEDURES

12.1 Emergency. During an Emergency as declared by the Operating Agent, in its sole discretion and consistent with Good Utility Practice, or the Security Coordinator as appointed by WSCC for the Operating Agent’s region, the Operating Agent has the sole discretion to direct Generator to increase or decrease real power production (measured in MW) and/or reactive power production (measured in MVAR), within the design and operational limitations of the Facility equipment in service at the time. The Operating Agent shall have sole discretion, exercised in accordance with Good Utility Practice, to determine that: (a) the transmission grid security is threatened, and (b) any generator(s) connected to the transmission grid must increase or decrease real power and/or reactive power production. Generator shall follow the Operating Agent’s orders and directives concerning Facility real power and/or reactive power output within the design limitations of the Facility’s equipment in service at the time. The Operating Agent shall restore the transmission system conditions to normal as quickly as possible to alleviate any such Emergency. The Operating Agent shall reasonably allocate the responsibility to provide real power and/or reactive power support to the transmission system during an Emergency on an equitable, non-discriminatory basis with respect to all generating units and other reactive compensation resources available to the Operating Agent. The Operating Agent, or any other Party as applicable, will compensate Generator, for a change in real power output

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in compliance with Operating Agent’s directive, except for reductions, interruptions or curtailment under the applicable OATT, pursuant to mutually agreed terms or pursuant to any applicable FERC-accepted tariff or rate schedule filed by Generator. The Operating Agent, or any other Party as applicable, will compensate Generator for a change in reactive power production pursuant to the terms and conditions of Article X.

12.2 Notice of Emergency. The Operating Agent shall provide Generator with prompt verbal or electronic notice of any Emergency which may reasonably be expected to affect Generator’s operation of the Facility, and Generator shall provide the Operating Agent with prompt verbal notice of any generation equipment Emergency which may reasonably be expected to affect the Operating Agent’s operations. Such verbal notification shall be followed within twenty-four (24) hours with written notification, which shall describe in reasonable detail the extent of the Emergency (including damage or deficiency), the anticipated length of the outage, and the corrective actions taken.

12.3 Immediate Action. In the event of an Emergency, the Party (either the Operating Agent or Generator) becoming aware of the Emergency may, in the exercise of its reasonable judgment and in accordance with Good Utility Practice, take such actions as are reasonable and necessary to prevent, avoid, or mitigate injury, danger, and loss, without liability to the other Party for its actions.

12.3.1 In the event that Generator has identified an Emergency involving the transmission system, Generator shall obtain the consent of the Operating Agent before manually performing any switching operations unless, in Generator’s reasonable judgment, exercised in accordance with Good Utility Practice, immediate action is required.

12.3.2 Either the Operating Agent or Generator shall have the right to disconnect the Facility without prior notice or liability to the other Party if, in such Party’s reasonable judgment and in accordance with Good Utility Practice, an Emergency exists and immediate disconnection is required to protect persons or property from damage caused by Generator’s interconnection or lack of proper or properly operating protective devices. Prior to an Emergency, for purposes of this Article 12.3.2, the Operating Agent may deem protective devices to be operating improperly if the Operating Agent’s review pursuant to Article XIII discloses insufficient maintenance on such devices or that maintenance records do not exist or are insufficient to establish that adequate maintenance on such devices has been performed, provided that the Operating Agent shall inform Generator, in writing following the Operating Agent’s review, of such conclusions regarding maintenance of such devices and provide Generator a reasonable opportunity to demonstrate to the Operating Agent’s satisfaction that adequate maintenance has been performed. The Party initiating the disconnection shall notify the other Party of such disconnection as soon as reasonably possible after the disconnection.

12.4 Disconnection of Facility in Event of Potential Emergency. If, at any time, the Operating Agent determines, in the exercise of its reasonable judgment and in accordance with Good Utility Practice, that the continued operation of the Facility would cause an Emergency, the Operating Agent may disconnect the Facility from the EPE Interconnection Facilities until such condition at the Facility giving rise to the potential Emergency ceases to exist. The Operating Agent shall

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not be liable to Generator for the Operating Agent’s actions unless such action constitutes willful misconduct on the part of the Operating Agent.

12.4.1 Notice of Disconnection. The Operating Agent shall provide Generator with as much advance notice as is reasonably practical under the circumstances of Operating Agent’s intent to disconnect the Facility in response to a condition at the Facility that would cause an Emergency. Subject to Article 3.7, the Operating Agent shall also provide Generator with information relating to the nature of the potential Emergency and the expected duration of the disconnection at the Interconnection Point.

12.4.2 Opportunity to Resolve Condition. To the extent reasonably practical, the Operating Agent shall allow Generator an opportunity to remove or remedy such condition at the Facility that would cause an Emergency before the Operating Agent disconnects the Facility.

12.4.3 Conference Regarding Condition. In the event of disconnection, the Operating Agent shall promptly confer with one of Generator’s Operating Committee representatives regarding the condition that gave rise to the disconnection. The Operating Agent shall provide Generator with its recommendation, if any, regarding the timely correction of the condition.

12.4.4 Restoration. The Operating Agent shall promptly reconnect the Facility when the condition giving rise to the potential Emergency ceases to exist and shall use reasonable efforts consistent with Good Utility Practice to minimize the duration of any disconnection.

12.5 Audit Rights. The Operating Agent and Generator shall keep and maintain records of any actions taken during an Emergency that may reasonably be expected to impact the others’ facilities and shall make such records available for review by the other or its auditor upon the request and expense of the other. Any request for such an audit shall be made no later than twenty-four (24) months following the actions taken in conjunction with the Emergency.

12.6 Abnormal Conditions. To the extent the Operating Agent is aware of any Abnormal Condition, the Operating Agent will provide Generator with reasonably prompt oral notification of such Abnormal Condition if it may reasonably be expected to affect Generator’s Facility or operations. To the extent that Generator is aware of any Abnormal Condition, Generator will provide the Operating Agent with reasonably prompt oral notification of such Abnormal Condition if it may reasonably be expected to affect the operations of the Operating Agent’s or EPE’s facilities. Subject to Article 3.7, any such oral notification provided hereunder shall include a description of the Abnormal Condition, its anticipated duration, and the action taken and/or to be taken with respect to the notifying Party’s facilities, and shall be followed as soon as practicable with written confirmation of the facts. Each Party shall cooperate and coordinate with the other Party in taking whatever actions on its facilities as are reasonably necessary to mitigate or eliminate the Abnormal Condition, including, to the extent necessary, adjusting the operation of equipment to within its rated operating parameters; provided, however, that such measures are consistent with Good Utility Practice and do not require operation of any of the Parties’ facilities outside their operating limits. The Operating Agent and Generator each reserves the right, in its sole discretion, to isolate or disconnect the Facility from the EPE Transmission System at the Afton Switching Station if it believes an Abnormal Condition, including an electric disturbance, may cause damage to its facilities. The Operating Agent, or

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any other Party as applicable, will compensate Generator, for a change in real power output in compliance with Operating Agent’s directive, except for reductions, interruptions or curtailment under the applicable OATT, pursuant to mutually agreed terms or pursuant to any applicable FERC-accepted tariff or rate schedule filed by Generator. The Operating Agent, or any other Party as applicable, will compensate Generator for a change in reactive power production pursuant to the terms and conditions of Article X. Generator will compensate Operating Agent or EPE, as applicable, for actions provided to Generator to mitigate Abnormal Conditions caused by Facility pursuant to mutually agreed terms or pursuant to any applicable FERC-accepted tariff or rate schedule filed by Operating Agent or EPE, as applicable.

Article XIII

MAINTENANCE

13.1 The Operating Agent Obligations. The Operating Agent shall maintain and repair/replace the EPE Interconnection Facilities: (a) in a safe and reliable manner; (b) in accordance with Good Utility Practice; and (c) in accordance with the terms and conditions of this Agreement.

13.2 Generator Obligations. Generator shall maintain and repair/replace the Facility and Generator’s Interconnection Facilities: (a) in a safe and reliable manner; (b) in accordance with Good Utility Practice; and (c) in accordance with the terms and conditions of this Agreement.

13.3 Maintenance Expenses. In accordance with Articles 5.3 and 5.4 and subject to Article 5.14, Generator shall be responsible for all expenses associated with maintaining and repairing/replacing the Interconnected Facilities. The Operating Agent agrees to provide Generator in June of each year with its best estimate of the costs required to operate and maintain the EPE Interconnection Facilities over the next twelve (12) months. These costs shall be billed and paid in accordance with Articles 7.2 and 7.3. The Operating Agent will notify Generator in advance of any increase in the cost of work to be performed if the total amount increases by twenty-five percent (25%) or more of the estimate provided to Generator. Any such increase shall be subject to Generator’s authorization, which shall not be unreasonably delayed, withheld or denied. In accordance with Article 5.4.4, EPE shall be responsible for all expenses associated with maintaining and repairing/replacing Interconnection System Upgrades after the Operation Date.

13.4 Coordination. Generator agrees to coordinate with the Operating Agent in accordance with procedures developed by the Operating Committee regarding the inspection, maintenance, and testing of those secondary systems in the Facility and Interconnected Facilities directly affecting the operation of the EPE Transmission System. To the extent possible, Generator shall provide five (5) Business Days’ advance written notice to the Operating Agent before undertaking such work.

13.5 Observation of Deficiencies. Each Party shall have the right, but not the obligation, to observe the testing and maintenance activities performed by the other Party with respect to facilities whose performance may adversely affect the reliability of the observing Party’s facilities. If the observing Party observes any deficiencies or defects associated with, or becomes aware of a lack of maintenance, inspections, or testing with respect to, any of the other Party’s facilities

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and equipment that might be reasonably expected to adversely affect the observing Party’s facilities and equipment, the observing Party shall provide prompt written notice to such other Party. Notwithstanding the foregoing, the observing Party shall have no liability for failure to give such notice. Upon receipt of such written notice, such Party shall take any necessary corrective actions in accordance with Good Utility Practice.

13.6 Review of Maintenance Records. Upon ten (10) Business Days’ written notice to Generator, Generator shall provide the Operating Agent with access to Generator’s maintenance, inspection, and testing records for Generator’s Interconnection Facilities and any other facilities whose operation may reasonably be expected to affect the reliability of the EPE Interconnection Facilities, or the EPE Transmission System. The other facilities shall include generator step up transformers, protection systems, metering, communications systems, breakers, automatic voltage regulators, generator governor and excitation systems. Upon ten (10) Business Days’ written notice to the Operating Agent, the Operating Agent shall, subject to Article 3.7, provide Generator with access to the Operating Agent’s maintenance, inspection, and testing records for the EPE Interconnection Facilities.

Article XIV

METERING

14.1 General. Prior to the Operation Date, EPE shall provide, install, and maintain Metering Equipment necessary to meet its obligations under this Agreement. Generator shall have the option, subject to EPE approval, to use EPE’s Metering Equipment for Facility operations. Beginning on the Operation Date, the Operating Agent shall assume responsibility for operating and maintaining the Metering Equipment. EPE shall own the Metering Equipment. At the Operating Agent’s option, the Metering Equipment shall be located or adjusted in such a manner to account for any transformation or interconnection losses between the location of the meter and the Interconnection Point. The location of the Metering Equipment and Generator’s verification meters are identified on Appendix D.

14.2 Testing. The Operating Agent shall inspect and test Metering Equipment on an annual basis or at such other time intervals as may be directed by the Operating Committee; provided, however, that Generator, may request, after demonstrating good cause, one additional inspection and test for Metering Equipment per year. In addition, any Party may request a special test of meters, but such Party shall bear the cost of such testing unless an inaccuracy shall be disclosed exceeding one percent (1%), in which case the Operating Agent shall be responsible for the costs of the special testing. Authorized representatives of each Party shall have the right to be present at all routine or special tests and to inspect any readings, testing, adjustment or calibration of the meters. The Operating Agent shall promptly correct any inaccuracy disclosed through such inspections and tests. For the purpose of checking the performance of the Metering Equipment, Generator may install check metering equipment, which such equipment shall be owned and maintained by Generator.

14.3 Data Metered. The following data shall be real-time metered and sent electronically to the Operating Agent’s SOCC: (a) net MW output of each generator of the Facility; (b) reactive power output of each generator of the Facility, both positive and negative; (c) 345 kV bus voltage; (d) indications (open or closed) of all circuit breakers; (e) indications (open or closed)

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of all circuit switches; (f) various alarm points, as reasonably determined by the Operating Agent; (g) various relay indications and relay alarms; and (h) any other data as determined by the Operating Agent.

14.4 Data Available Upon Request. The Operating Agent shall provide to Generator and EPE all metering quantities in analog and/or digital form, whichever is available, upon request.

14.5 Costs. Except as otherwise provided for in this Article XIV, Generator shall bear all reasonable costs associated with the provision of metering data to Generator. All such costs shall be separately stated on the invoice sent to Generator by EPE or the Operating Agent, as applicable.

Article XV

SAFETY

15.1 General. All work performed by a Party shall be performed in accordance with Good Utility Practice and all Applicable Laws and Regulations, Environmental Laws, and other requirements regarding the safety of persons and property.

15.2 Environmental Releases. No later than twenty-four (24) hours after a Party becomes aware of a Release of any Hazardous Substances, any asbestos or lead abatement activities, or any type of remediation activities, such Party shall provide written notice to the other Party of such Release or activities, describing in reasonable detail the nature of such Release or activities. Such Party shall also promptly provide the other Party with copies of any reports filed with any Governmental Authority regarding such Release or activities.

15.3 Other Environmental Impact. No Party shall take any action(s) knowing that such action(s) might be reasonably expected to have a material adverse environmental impact upon the operations of the other Party without prior written notification and agreement between the Parties.

Article XVI

COMMUNICATIONS

16.1 Equipment. Generator, at its own expense, shall maintain satisfactory communications with the Operating Agent or its designated representative. At Generator’s expense, Generator shall install and maintain real-time operating communications with the Operating Agent’s SOCC to the satisfaction of the Operating Agent or its designated representative. The data circuit(s) shall extend from Generator’s Facility to a location(s) specified by the Operating Agent. Any required maintenance of such communications equipment shall be performed at Generator’s expense, but may be performed by Generator or by the Operating Agent. EPE, at Generator’s expense, will own, operate and maintain the communications system necessary to support the switchyard and transmission interconnection with the existing transmission system, including switchyard RTU(s), protective relaying, telemetry, station phones, and other similar EPE systems. Generator will own, operate and maintain the communication system required to support the Generator, including Generator RTU(s), telemetry, ringdown phones, administrative communications such as LAN and telephones and other similar Generator systems.

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16.2 Remote Terminal Unit. A Remote Terminal Unit (“RTU”) or equivalent data collection and transfer equipment acceptable to Generator and the Operating Agent shall be installed by Generator or by EPE at Generator’s expense, to gather accumulated and instantaneous data to be telemetered to a location(s) designated by the Operating Agent through use of a dedicated point-to-point data circuit(s). Generator shall install or facilitate installation of such equipment as soon as practicable, provided that installation shall be accomplished prior to the date of unit testing or the Commercial Operation Date, whichever comes first. The communication protocol for this data circuit(s) shall be specified by the Operating Agent. Instantaneous bi-directional analog real power and reactive power flow information must be telemetered directly to the location(s) specified by the Operating Agent.

Article XVII

INFORMATION REPORTING

17.1 General. Generator shall provide to the Operating Agent all information, documents, or data, pertaining to the operations of the Facility, required for the Operating Agent to fulfill its obligations to NERC, WSCC, the RTO (if applicable) or any Governmental Authority requiring system information. Such information, documents or data shall be supplied in the format as required by NERC, WSCC, the RTO (if applicable) or any Governmental Authority and within a reasonable time frame designated by the Operating Agent to meet these obligations.

17.2 Compliance Monitoring Reporting. Generator shall provide all information, documents, or data, pertaining to the operations of the Facility, requested by NERC, WSCC, the RTO (if applicable) or any other entity with jurisdiction requiring system information for purposes of compliance monitoring programs including RMS. Such information, documents, or data shall be provided to the Operating Agent if required by the specific compliance program or to the extent otherwise required by this Agreement. Such information, documents, or data shall be supplied in the format as required by NERC, WSCC, the RTO (if applicable) or any other entity with jurisdiction and within the time frame designated by such compliance program sponsor to meet these obligations.

17.3 Regulatory Agency Reporting. Generator shall provide to the Operating Agent all information, documents, or data, pertaining to the operations of the Facility, required by the Operating Agent to fulfill reporting obligations to any Governmental Authority including FERC. Such information, documents, or data shall be supplied in the format as required by any Governmental Authority including FERC and within a reasonable time frame designated by the Operating Agent to meet these obligations.

17.4 Penalties. Generator shall be responsible for reimbursement to the Operating Agent of any economic sanctions or portions thereof, as applicable, or penalties incurred or imposed upon the Operating Agent due solely to Generator’s failure to provide information, documents, or data, pertaining to the operations of the Facility, in the required format within the time frame specified by the Operating Agent, or the compliance monitoring program, except to the extent that Generator’s failure is due solely to the Operating Agent’s or any of its Agents’ negligence or willful misconduct.

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Article XVIII

DOCUMENTATION

18.1 General. Each Party shall provide the other Party with appropriate documentation, consistent with Good Utility Practice, in the form of written test records, operation and maintenance procedures, drawings, material lists, or descriptions whenever a Party makes a change, alteration, or modification to its property, equipment, or facilities that could reasonably be expected to affect the other Party, or whenever such documentation is necessary to ensure the safe and reliable operation of the EPE Transmission System, the Facility, or the Interconnected Facilities, pursuant to Good Utility Practice or required by the Operating Committee. EPE’s obligation to provide documentation pursuant to this Article is subject to Article 3.7.

18.2 Drawings. The Operating Agent shall identify, number, and provide Generator with a duplicate set of current drawings that represent equipment or facilities that shall be used or operated at or near the Interconnection Point, which shall consist of one or more of the following: (a) system one-line drawings that include breaker and switch designations – single page format drawings used for dispatch and operation purposes; (b) one-line drawings – prints used in conceptual design which provide detail on facility and system interconnections; (c) elementary diagrams – drawings which provide a higher level of detail than one-line drawings and identify on a single-line basis current and voltage transformer locations, protection relay types, and meter and control connections; (d) three-line diagrams – drawings which provide the highest level of detail for the facilities in a three-line format with specific current and voltage transformer connections, relay and meter connections; (e) schematic drawings or elementaries – drawings which provide information on apparatus controls, switch developments, etc.; (f) relay and control panel front view and wiring diagrams – drawings which describe physical panel layout, relay, terminal block and device locations, wiring, and other construction details; and (g) other physical drawings – drawings which include information on foundations, equipment layouts, grounding panel construction, site plans, etc.

Article XIX

FORCE MAJEURE

19.1 Definition. As used in this Agreement, the term “Force Majeure” means any cause that is beyond the reasonable control of the Party affected which, despite the affected Party’s exercise of Due Diligence to prevent or overcome, prevents the performance by such affected Party of its obligations under this Agreement. Subject to the foregoing, “Force Majeure” shall include sabotage, strikes or other labor difficulties, riots, civil disturbances, acts of God, wars, acts of public enemies, epidemics, drought, earthquake, flood, explosion, fire, lightning, landslides, or similar cataclysmic event, breakage or accident to machinery or equipment, order, regulation, or restriction imposed by governmental military or lawfully established civil authorities, the occurrence of an event described in the first sentence of Article 2.4 (provided that the Party asserting Force Majeure based on such occurrence complies with its obligations under Article 2.4), or any other cause, whether of the kind enumerated herein or otherwise. A Force Majeure event does not include : (a) economic hardship of or loss of markets by a Party; (b) the unavailability of transmission or distribution capability, unless the Party claiming Force Majeure has contracted for firm transmission and such unavailability is the result of a “force majeure” event or “uncontrollable force” or a similar term as defined under the applicable

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transmission tariff; (c) events resulting from, or attributable to, normal wear and tear experienced in power generation, interconnection, and transmission materials and equipment; and (d) events attributable to negligence or willful misconduct, failure to comply with any Applicable Laws and Regulations, any default under this Agreement, or any failure to act in accordance with Good Utility Practice in each case by the Party claiming Force Majeure.

19.2 Performance Excused. If any Party is rendered wholly or partially unable to perform under this Agreement because of a Force Majeure event, such Party shall be excused from such obligations to the extent that the occurrence of the Force Majeure event prevents such Party’s performance and such Party shall not be liable for any resulting damages, provided that: (a) the non-performing Party provides the other Party with prompt verbal notice of the occurrence of the Force Majeure event, and provides written notice describing in reasonable detail the nature of the Force Majeure event within three (3) Business Days of the Force Majeure event; (b) the suspension of performance shall be of no greater scope and of no longer duration than is reasonably required by the Force Majeure event; (c) the non-performing Party uses Due Diligence to remedy its inability to perform; and (d) as soon as the non-performing Party is able to resume performance of its obligations excused as a result of the occurrence, it gives prompt written notification thereof to the other Party.

19.3 Labor Issues. No Party shall be required to settle a strike or other labor dispute affecting its operations.

19.4 Payment Not Excused. Nothing in this Article XIX shall excuse any Party from making payments due pursuant to the terms and conditions of this Agreement for the period prior to the occurrence of the Force Majeure event.

Article XX

INDEMNIFICATION

20.1 INTERCONNECTION INDEMNITY. GENERATOR SHALL AT ALL TIMES INDEMNIFY AND HOLD HARMLESS THE OPERATING AGENT AND EPE FOR, AGAINST AND FROM ANY AND ALL DAMAGES, LOSSES, CLAIMS, INCLUDING CLAIMS AND ACTIONS RELATING TO INJURY TO OR DEATH OF ANY PERSON OR DAMAGE TO OR LOSS OF ANY PROPERTY, DEMANDS, SUITS, RECOVERIES, COSTS AND EXPENSES, COURT COSTS, ATTORNEY FEES, AND ALL OTHER OBLIGATIONS BY OR TO THIRD PARTIES, ARISING OUT OF OR RESULTING FROM THE OPERATING AGENT’S OR EPE’S PERFORMANCE OF ITS OBLIGATIONS UNDER THIS AGREEMENT ON BEHALF OF GENERATOR EXCEPT IN CASES OF NEGLIGENCE OR INTENTIONAL WRONGDOING BY THE OPERATING AGENT OR EPE.

20.2 RECIPROCAL INDEMNITY. EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT, EACH PARTY SHALL INDEMNIFY AND HOLD HARMLESS THE OTHER PARTY, ITS AFFILIATES, AGENTS, SUCCESSORS, REPRESENTATIVES AND PERMITTED ASSIGNS FOR, AGAINST AND FROM ANY CLAIM, LIABILITY, DAMAGE, LOSS OR EXPENSE OF ANY KIND OR NATURE (INCLUDING REASONABLE ATTORNEYS’ FEES), (A) FOR PERSONAL INJURY TO OR DEATH OF ANY PERSON, (B) FOR LOSS OF OR DAMAGE TO PROPERTY OF THIRD PARTIES OR

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THE REAL PROPERTY OR TANGIBLE PERSONAL PROPERTY OF SUCH OTHER PARTIES, OR (C) ARISING OUT OF OR RESULTING FROM PERFORMANCE OF OBLIGATIONS UNDER THIS AGREEMENT, IN EACH INSTANCE TO THE EXTENT DETERMINED TO BE ATTRIBUTABLE TO THE NEGLIGENCE, GROSS NEGLIGENCE, WILLFUL MISCONDUCT, OR STRICT LIABILITY IN TORT OF OR BREACH OF THIS AGREEMENT BY THE INDEMNITOR OR ITS AFFILIATES, AGENTS, SUCCESSORS OR PERMITTED ASSIGNS.

20.3 DAMAGE DISCLAIMER. THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY. THE OBLIGOR’S LIABILITY SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IN NO EVENT SHALL ANY PARTY BE LIABLE FOR SPECIAL, INDIRECT, INCIDENTAL, CONSEQUENTIAL OR PUNITIVE DAMAGES, INCLUDING LOSS OF PROFIT OR REVENUE, LOSS OF THE USE OF EQUIPMENT, COST OF CAPITAL, COST OF TEMPORARY EQUIPMENT OR SERVICES, WHETHER BASED ON BREACH OF CONTRACT, NEGLIGENCE, GROSS NEGLIGENCE, WILLFUL MISCONDUCT, STRICT LIABILITY OR OTHER CAUSES OF ACTION. ALL PAYMENTS DUE FOR SERVICES UNDER THIS AGREEMENT SHALL BE DEEMED TO CONSTITUTE DIRECT (NOT SPECIAL, INCIDENTAL, INDIRECT OR CONSEQUENTIAL) DAMAGES FOR PURPOSES OF THIS ARTICLE 20.3. THE PROVISIONS AND DISCLAIMERS OF THIS ARTICLE 20.3 SHALL NOT APPLY TO CLAIMS FOR PERSONAL INJURY OR DEATH AND SHALL NOT APPLY TO ARTICLE 22.7.

20.4 Indemnities Reformed. The indemnities set forth in this Article XX shall be construed to be effective to the maximum extent permitted by Applicable Laws and Regulations. To the extent that any of the indemnities are determined to be unenforceable or void under Applicable Laws and Regulations, the indemnities shall be reformed and restated to the extent necessary to render them effective.

20.5 Indemnification Procedures. If any Party intends to seek indemnification under this Article XX from any other Party, the Party seeking indemnification shall give such other Party written notice of such claim within thirty (30) days of the commencement of, or actual knowledge of, such claim. Such notice shall describe the claim in reasonable detail and shall indicate the amount (estimated, if necessary) of the claim that has been or may be sustained by such Party. To the extent that the other Party is actually and materially prejudiced as a result of the failure to provide such notice, the other Party’s liability under the provisions of this Article XX shall be reduced proportionately to such prejudice. The Party being indemnified may, if in its reasonable judgment its interests are adverse to the interests of the indemnifying Party, elect to assume at its own expense and by its own counsel the defense of the claim, in which case the indemnifying Party shall cooperate in good faith at its own expense with the Party being indemnified in such defense. No Party shall settle or compromise any claim without the prior written consent of the Party from which it is seeking indemnification; provided, however, that such consent shall not be unreasonably withheld, delayed or denied.

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20.6 Additional Indemnification Provisions. If a court of competent jurisdiction determines that NMSA 1978, §56-7-1 is applicable to this Agreement, then nothing in this Article 20.6 or any other indemnification provision of this Agreement shall extend to liability, claims, damages, losses, or expenses, including attorney fees, arising out of:

20.6.1 The preparation or approval of maps, drawings, opinions, reports, surveys, change orders, designs, or specifications by the indemnitee, or the employees or agents of the indemnitee; or

20.6.2 The giving of or failure to give directions or instructions by the indemnitee, or the employees or agents of the indemnitee, where such giving or failure to give directions or instructions is the primary cause of bodily injury to persons or damage to property.

20.7 Survival. The indemnification obligations, covenants and disclaimers, under this Article XX shall continue in full force and effect regardless of whether this Agreement has expired or been terminated or cancelled and shall not be limited in any way by any limitation on insurance, on the amount or types of damages, or by any compensation or benefits payable by the Parties under any applicable workers’ compensation acts, disability benefit acts, or other employee acts.

Article XXI

INSURANCE

21.1 Generator. Without limiting any obligations or liabilities under this Agreement, Generator shall, at its expense, provide and maintain in effect for the term of this Agreement, insurance against the risks set forth below. All insurance shall include waivers of subrogation in favor of EPE and the Operating Agent.

21.1.1 Workers’ compensation insurance with minimum statutory limits to cover obligations imposed by federal and state statutes applicable to the Generator’s employees and employer’s liability insurance with a minimum limit of one million dollars ($1,000,000) per accident.

21.1.2 Commercial general liability insurance, including contractual liability, broad form property damage, premises operations, and personal injury coverage in the amount of twenty-five million dollars ($25,000,000) per occurrence for bodily injury and property damage. Such insurance shall cover EPE (and its affiliated companies) and the Operating Agent as additional insureds.

21.2 EPE or Operating Agent. Without limiting any obligations or liabilities under this Agreement, EPE or Operating Agent shall provide and maintain in effect for the term of this Agreement, insurance against the risks set forth below. All insurance shall include waivers of subrogation in favor of Generator.

21.2.1 Workers’ compensation insurance with minimum statutory limits to cover obligations imposed by federal and state statutes applicable to the employees of EPE or Operating Agent and employer’s liability insurance with a minimum limit of one million dollars ($1,000,000) per accident.

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21.2.2 Commercial general liability insurance, including contractual liability, broad form property damage, premises operations, and personal injury coverage in the amount of twenty-five million dollars ($25,000,000) per occurrence for bodily injury and property damage. Such insurance shall cover Generator as an additional insured.

21.3 Notice of Cancellation. All policies shall provide for thirty (30) calendar days’ prior written notice of cancellation or material adverse change and ten (10) calendar days’ prior written notice of non-payment of premiums. Copies of any such notice shall be provided to each Party and the Operating Agent. Prior to the Operation Date and annually thereafter, each Party shall provide, upon request, evidence of insurance to the Operating Agent and the other Party.

21.4 Self-Insurance. At its option, each Party may, with adequate credit assurance provided to the other Party, self-insure all or part of the insurance required in this Article XXI; provided however, that all other provisions of this Article XXI, including waiver of subrogation and additional insured status, shall remain enforceable. A Party’s election to self-insure shall not in any manner result in a reduction of rights and/or benefits otherwise available to the other Party through formal insurance policies and endorsements as specified in this Article XXI. Each Party shall be responsible for its respective amounts of self-insurance retentions and/or deductibles.

Article XXII

DEFAULT

22.1 General. A Party shall be deemed to have breached this Agreement upon the occurrence of any of the events specified in Article 22.2. A Party shall be deemed to be in default of its obligations under this Agreement upon its failure to cure such breach in accordance with the procedures set forth in this Article XXII.

22.2 Events Constituting Breach. The following events shall constitute events of breach by a Party (“Breaching Party”) under this Agreement:

(a) the failure by the Breaching Party to make any payment as required under the terms of this Agreement;

(b) the failure by the Breaching Party to comply with any material term or condition of this Agreement, including any material breach of a representation, warranty, or covenant of this Agreement;

(c) the Breaching Party (or any entity guaranteeing the obligations of such Breaching Party): (i) files or consents by answer or otherwise to a filing against it of any petition or case seeking relief under any federal, state, or foreign bankruptcy, insolvency, or similar law (collectively, “Bankruptcy Laws”); (ii) makes a general assignment for the benefit of a creditor(s); (iii) applies for or consents to the appointment of a custodian, receiver, trustee, conservator, or other officer with similar powers over it or over any substantial part of its property (“Custodian”); (iv) takes corporate action for the purpose of any of the events described

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in Article 22.2(c)(i) – (iii), above; (v) is dissolved; (vi) by decree of a court of competent jurisdiction, is adjudicated insolvent; or (vii) is unable to provide adequate assurances to the other Party of the Breaching Party’s continued ability to perform;

(d) a Governmental Authority enters or issues an order or a decree with respect to the Breaching Party: (i) appointing a Custodian; (ii) constituting an order for relief under, or approving a petition or case for relief or reorganization or any other petition or case to take advantage of, any Bankruptcy Laws; or (iii) ordering its dissolution, winding-up, or liquidation;

(e) the assignment of this Agreement by the Breaching Party in a manner inconsistent with the terms and conditions of this Agreement;

(f) the failure of the Breaching Party to provide access rights, or the Breaching Party’s attempt to revoke or terminate such access rights, as provided under this Agreement; and

(g) the failure by the Breaching Party to provide information or data to the other Party (“Non-Breaching Party”) as required under this Agreement, provided that the Non-Breaching Party seeking such information or data requires such information or data to satisfy its obligations under this Agreement.

22.3 Notice by Breaching Party. In the event of a breach under Article 22.2(c) or Article 22.2(d), the Breaching Party shall provide the Non-Breaching Party notice of the event of breach within three (3) Business Days of the occurrence of such event of breach. Such notice shall be in writing and set forth in reasonable detail the nature of the event of breach.

22.4 Cure and Default. Upon obtaining knowledge of an event of breach under Article XXII, the Non-Breaching Party shall give written notice to the Breaching Party, describing, in reasonable detail, to the extent known and applicable, the actions necessary to cure the event of breach. Upon receiving such notice, the Breaching Party shall have thirty (30) days to cure such breach. If the breach cannot be cured within thirty (30) days, the Breaching Party shall commence in good faith all actions that are reasonable and appropriate to cure such breach within such thirty (30) day period, and thereafter shall pursue such action to completion. In the event that the Breaching Party (a) fails to cure such breach or fails to take all actions that are reasonable and appropriate to cure such breach within thirty (30) days of receiving the notice from the Non-Breaching Party or (b) having commenced cure within such thirty (30) day period, fails to complete cure within one hundred eighty (180) days of receiving the notice from the Non-Breaching Party, the Breaching Party shall be in default of this Agreement.

22.5 Continued Operations. In the event of a breach or a default by a Party, but prior to termination of this Agreement, the Parties shall continue to operate and maintain such power systems, protective devices, metering equipment, transformers, communications equipment, building facilities, software, documentation, structural components, and other facilities, equipment, and

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appurtenances that are reasonably necessary to operate and maintain the EPE Transmission System and the Facility in a safe and reliable manner.

22.6 Upon Default. Upon default, the non-defaulting Party may: (a) commence an action to require the Party in default to remedy such default and specifically perform its obligations under this Agreement; (b) pursue other rights and remedies as it may have in law or equity (subject to the limitations set forth in Article XX); and/or (c) terminate this Agreement pursuant to Article 23.2. Notwithstanding the foregoing, EPE may not terminate this Agreement upon a default by Generator provided that (x) EPE can be made whole by monetary damages, (y) Generator agrees to compensate EPE for damages suffered by it as a result of such default (subject to the limitations set forth in Article XX) and (z) such default does not pose a threat to the safety or reliability of the EPE Transmission System.

22.7 Generator’s Default in Payment for Equipment. If Generator is in default of its obligation to reimburse or otherwise pay EPE for the cost of all or any part of EPE Interconnection Facilities (the portion of such equipment for which Generator is in default of payment is herewith referred to as “Default Equipment”), then Generator shall pay EPE the sum of (a) the costs incurred by or on behalf of EPE for the acquisition, installation and maintenance of such Default Equipment (including appropriate carrying charges on such Default Equipment calculated from the date of acquisition), (b) the costs incurred by or on behalf of EPE for labor with respect to the Default Equipment, and (c) interest at the Interest Rate on the amounts specified in subparts (a) and (b) above calculated from the date of breach. If Generator is in default of its obligation to reimburse or otherwise pay EPE for the cost of all or any part of the Interconnection System Upgrades (the portion of such upgrade for which Generator is in default of payment is herewith referred to as “Default Upgrade”), then Generator shall pay EPE the sum of (x) the costs incurred by or on behalf of EPE for the acquisition, installation and maintenance of such Default Upgrade (including appropriate carrying charges on such Default Upgrade calculated from the date of acquisition), (y) the costs incurred by or on behalf of EPE for labor with respect to the Default Upgrade, and (z) interest at the Interest Rate on the amounts specified in subparts (x) and (y) above calculated from the date of breach.

Article XXIII

TERMINATION

23.1 Expiration of Term. Except as otherwise provided in this Article XXIII, this Agreement shall terminate at the conclusion of the term set forth in Article 2.3.

23.2 Termination in the Event of Default. Subject to Articles 23.3 and 22.6, EPE or Generator may each terminate this Agreement upon the default by the other Party upon: (a) providing written notice of termination to the other Party; and (b) to the extent required, filing a notice of termination with FERC, which must be accepted for filing by FERC.

23.3 Survival. Termination of this Agreement shall not relieve any Party of any of its liabilities or obligations arising hereunder prior to the effective date of the termination of this Agreement. In the event of termination, each Party may take whatever judicial or administrative actions are necessary to enforce its rights under this Agreement.

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23.4 Disconnection and Disposition of Facilities Upon Termination. Upon termination of this Agreement, unless otherwise ordered or approved by FERC, the Operating Agent may disconnect the Facility from the EPE Transmission System at the Afton Switching Station in accordance with a plan for disconnection which the Operating Committee approves or upon which the Parties agree. EPE may, in its sole discretion, retain or dispose of any EPE Interconnection Facilities and Interconnection System Upgrades, provided that in either case Generator shall pay any applicable Termination Costs.

Article XXIV

CREDITWORTHINESS

For purposes of determining Generator’s ability to meet its obligations hereunder during the term of this Agreement, EPE (including in its capacity as Operating Agent) may require Generator to provide and maintain in effect a letter of credit or other form of security to meet Generator’s responsibilities and obligations or an alternate form of security consistent with commercial practices established by the Uniform Commercial Code that protects EPE against non-payment. In any instance where facilities to be built require EPE to incur costs, EPE will not be obligated to incur any costs until Generator provides EPE with a letter of credit or other reasonable form of security acceptable to EPE, consistent with commercial practices as established by Uniform Commercial Code, equivalent to the costs of the new facilities or upgrades.

Article XXV

RELATIONSHIP OF THE PARTIES

EPE (including in its capacity as Operating Agent) and Generator are independent contractors. Nothing in this Agreement creates, or is intended to create, an association, trust, partnership or joint venture or impose a trust or partnership duty, obligation or liability on or with regard to either of the Parties. Each Party shall be individually responsible for its own covenants, obligations, and liabilities under the terms and conditions of this Agreement.

Article XXVI

REPRESENTATIONS AND WARRANTIES

26.1 Representations of EPE. EPE represents and warrants to the Generator as follows:

(a) EPE is a corporation duly organized, validly existing, and in good standing under the laws of the State of Texas and EPE has the requisite corporate power and authority to carry on its business as now being conducted;

(b) EPE has the requisite corporate power to execute and deliver this Agreement and to carry out the actions required of it by this Agreement. The execution and delivery of this Agreement and the actions it contemplates have been duly and validly authorized by EPE and no other corporate proceedings on the part of EPE are necessary to authorize this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by EPE and constitutes a legal, valid, and binding agreement of EPE enforceable against it according to its terms

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and conditions, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws of general application relating to or affecting the enforcement of creditors’ rights and by general equitable principles;

(c) EPE is not in violation of any Applicable Laws and Regulations promulgated or judgment entered by any Governmental Authority, which individually or in the aggregate would adversely affect EPE’s entering into or performance of its obligations under this Agreement;

(d) EPE’s entering into and performance of its obligations under this Agreement will not give rise to any default under any agreement to which it is a party; and

(e) EPE shall comply with all Applicable Laws and Regulations of all Governmental Authorities having jurisdiction over EPE or the transactions under this Agreement and with which failure to comply could reasonably be expected to have a material adverse effect on EPE.

26.2 Representations of Generator. Generator represents and warrants to EPE as follows:

(a) Generator is a corporation duly organized, validly existing, and in good standing under the laws of the State of New Mexico and Generator has the requisite corporate power and authority to carry on its business as now being conducted;

(b) Generator has the requisite corporate power to execute and deliver this Agreement and to carry out the actions required of it by this Agreement. The execution and delivery of this Agreement and the actions it contemplates have been duly and validly authorized by Generator and no other corporate proceedings on the part of Generator are necessary to authorize this Agreement or to consummate the transactions contemplated hereby. This Agreement has been duly and validly executed and delivered by Generator and constitutes a legal, valid, and binding agreement of Generator enforceable against it according to its terms and conditions, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws of general application relating to or affecting the enforcement of creditors’ rights and by general equitable principles;

(c) Generator is not in violation of any Applicable Laws and Regulations promulgated or judgment entered by any Governmental Authority, which individually or in the aggregate would adversely affect Generator’s entering into or performance of its obligations under this Agreement;

(d) Generator’s entering into and performance of its obligations under this Agreement will not give rise to any default under any agreement to which it is a party; and

(e) Generator shall comply with all Applicable Laws and Regulations of all Governmental Authorities having jurisdiction over Generator or the transactions under this Agreement and with which failure to comply could reasonably be expected to have a material adverse effect on EPE.

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26.3 Representations of Each Party. The representations and warranties set forth in Articles 26.1 and 26.2 shall continue in full force and effect for the term of this Agreement.

Article XXVII

ASSIGNMENT

27.1 General. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and permitted assigns, but neither this Agreement nor any of the rights, interests, or obligations hereunder shall be assigned by any Party, including by operation of law, without the prior written consent of the other Party, such consent not to be unreasonably withheld or delayed; provided, however, that such prior consent shall not be required (a) for an assignment to an Affiliate or (b) for security for a financing party. Any assignment of this Agreement in violation of this Article XXVII shall be, at the option of the non-assigning Party, void. The assignee shall expressly assume all of the assignor’s obligations under this Agreement.

27.2 EPE. Notwithstanding Article 27.1, any party with which EPE may consolidate, or into which it may merge, or into which it may convey or transfer substantially all of its electric utility assets or part of the EPE Transmission System that includes the EPE Interconnection Facilities and Interconnection System Upgrades, or its interest in the Afton Switching Station, shall automatically and without the consent or approval of Generator succeed to all of EPE’s rights, interests, duties and obligations under this Agreement.

27.3 Generator. Notwithstanding Article 27.1, any party with which Generator may consolidate, or into which it may merge, or into which it may convey or transfer substantially all of its electric utility assets shall automatically and without the consent or approval of EPE succeed to all of Generator’s rights, interests, duties and obligations under this Agreement.

27.4 No Relief in Event of Assignment. No assignment shall relieve the assigning Party of its obligations under this Agreement in the event that the assignee fails to perform under the terms and conditions of this Agreement, unless and until the assignee agrees in writing to assume the obligations and duties of the assigning Party and the non-assigning Party reasonably determines that the assignee is no less technically and financially capable of performing its obligations under the Agreement than the assigning Party.

Article XXVIII

CONFIDENTIALITY

28.1 General. During the term of this Agreement and for a period of twelve (12) months after the expiration or termination of this Agreement, except as otherwise provided in this Article XXVIII, each Party shall hold in confidence and shall not disclose any Confidential Information to any Person. A Party may disclose Confidential Information received from the other Party to the receiving Party’s auditors and attorneys, Persons providing financing to the receiving Party, and to other third parties as may be necessary for the receiving Party to perform its obligations under this Agreement. To the extent that any disclosure of Confidential Information is necessary, the disclosing Party shall endeavor to preserve the confidentiality of the Confidential Information.

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28.2 Scope. Confidential Information shall not include any information that the receiving Party can demonstrate: (a) is generally available to the public other than as a result of a disclosure by the receiving Party; (b) was in the lawful possession of the receiving Party on a non-confidential basis prior to receiving it from any other Party; (c) was supplied to the receiving Party without any restrictions by a third party who, to the knowledge of the receiving Party, was under no obligation to any other Party to keep the information confidential; (d) was independently developed by the receiving Party; (e) is, or becomes, publicly known, through no wrongful act or omission of the receiving Party or breach of this Agreement; or (f) is required, in accordance with Article 28.5, to be disclosed to any Governmental Authority or is otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding establishing rights or obligations under this Agreement. Confidential Information is not considered confidential if the Party that designated such information as confidential notifies the other Party that such information is no longer confidential.

28.3 Rights in Confidential Information. Each Party retains all rights, title, and interest in the Confidential Information that it discloses to the other Party. The disclosure by a Party to the other Party of Confidential Information shall not be deemed a waiver by any Party or any other Person or entity of the right to protect the Confidential Information from public disclosure.

28.4 Standard of Care. Each Party shall use the same standard of care to protect Confidential Information that it receives as it uses to protect its own Confidential Information from disclosure, publication, or dissemination.

28.5 Required Disclosures. If a Governmental Authority requests or requires a Party to disclose Confidential Information, such Party shall provide prompt notice to the Party that provided the Confidential Information of such request or requirement so that such other Party may seek an appropriate protective order or waive compliance with the terms of this Agreement. Notwithstanding the absence of a protective order or waiver, a Party may disclose such Confidential Information which it is legally required to disclose. Each Party shall use Commercially Reasonable Efforts to obtain reliable assurances that confidential treatment will be accorded to Confidential Information required to be disclosed.

28.6 Possession of Confidential Information at Termination of Agreement. Upon the termination or expiration of this Agreement and within ten (10) days of receipt of a written request from the other Party, a Party shall destroy, erase, delete, or return to such other Party any and all written or electronic Confidential Information received from the other Party and shall retain no written or electronic copies of any Confidential Information.

28.7 Remedies Regarding Confidentiality. The Parties agree that monetary damages by themselves may be inadequate to compensate a Party for another Party’s breach of its obligations under Article XXVIII. Each Party accordingly agrees that the other Party may seek equitable relief, by way of injunction or otherwise, if it breaches or threatens to breach its obligations under Article XXVIII.

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Article XXIX

DISPUTE RESOLUTION

29.1 Dispute Resolution by Operating Committee. To the extent that a dispute arises under this Agreement, the Party raising such dispute shall provide written notice of such dispute to the other Party. Within ten (10) Business Days (or such other period as the Parties may agree upon) of the receipt of the notice by such Party, the Operating Committee shall convene in an attempt to resolve the dispute. If the Operating Committee is able to resolve the dispute, such resolution shall be reported in writing and shall be binding on the Parties.

29.2 Dispute Resolution by Senior Management. If the Operating Committee is unable to resolve the dispute within thirty (30) Business Days of the receipt of such notice, then the Parties shall refer the dispute to their respective senior management for resolution. If the senior management is able to resolve the dispute, such resolution shall be reported in writing and shall be binding on the Parties. In the event the senior management is unable to resolve the dispute within thirty (30) Business Days (or such other period as the Parties may agree upon) of referral, the Parties may elect to proceed to arbitration pursuant to Article 29.3 or if the Parties do not agree to proceed to arbitration within thirty (30) Business Days of the referral of the dispute to senior management, then each Party shall have the right to pursue any other rights or remedies that may be available at law or equity, subject to Article 20.3.

29.3 Arbitration.

29.3.1 Commencement of Arbitration Proceeding. If the Operating Committee and the senior management are unable to resolve a dispute arising under this Agreement pursuant to Articles 29.1 and 29.2, the Parties, by mutual written agreement, may submit the dispute to arbitration. Each Party shall submit a written statement detailing the nature of the dispute, designating the issue(s) to be arbitrated, identifying the provisions of this Agreement under which the dispute arose, and setting forth such Party’s proposed resolution of such dispute. The arbitration shall be conducted in accordance with the provisions of this Article XXIX, unless otherwise agreed in writing by the Parties.

29.3.2 Appointment of Arbitrator. Within ten (10) days of the date of the Parties’ written agreement to submit a dispute to arbitration, a representative of each Party shall meet for the purpose of selecting an arbitrator. If the Parties’ representatives are unable to agree on an arbitrator within twenty (20) days of the date of the Parties’ written agreement to submit the dispute to arbitration, then an arbitrator shall be selected in accordance with the procedures of the American Arbitration Association (“AAA”). Whether the arbitrator is selected by the Parties’ representatives or in accordance with the procedures of the AAA, the arbitrator shall, to the extent reasonably practicable or unless otherwise agreed by the Parties, have the qualifications and experience in the occupation, profession, or discipline relevant to the subject matter of the dispute.

29.3.3 Arbitration Proceedings. Any arbitration proceeding shall be conducted in accordance with the commercial arbitration rules of the AAA in effect on the date of the notice, except as may be specifically modified in this Agreement.

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29.3.4 Authority of Arbitrator. The arbitrator shall be bound by the provisions of this Agreement where applicable, and shall have no authority to modify any terms and conditions of this Agreement in any manner. The arbitrator shall render a decision, and may determine that monetary damages are due to a Party or may issue a directive that a Party take certain actions or refrain from taking certain actions, but shall not be authorized to order any other form of relief; provided, however, that nothing in this Article 29.3 shall preclude the arbitrator from rendering a decision which adopts the resolution of the dispute proposed by a Party. Unless otherwise agreed to by the Parties, the arbitrator shall render a decision within forty-five (45) days of the conclusion of the arbitration hearing, and shall notify the Parties in writing of such decision and the reasons supporting such decision. The decision of the arbitrator shall be final and binding upon the Parties and may be enforced or challenged in any court of competent jurisdiction. The arbitrator shall have no authority to award any damages inconsistent with the terms of this Agreement. The decision must also be filed at FERC if it affects FERC-jurisdictional rates, terms, and conditions of service or facilities.

29.3.5 Expenses and Costs. The fees and expenses of the arbitrator shall be shared equally by the Parties, unless the arbitrator specifies a different allocation. All other expenses and costs of the arbitration proceeding shall be the responsibility of the Party incurring such expenses and costs.

29.3.6 Location of Arbitration Proceedings. Unless otherwise agreed by the Parties, any arbitration proceedings shall be conducted in El Paso, Texas.

29.3.7 Confidentiality. The existence, contents, or results of any arbitration proceeding under this Article XXIX may not be disclosed without the prior written consent of the Parties; provided, however, that any Party may make disclosures as may be required to fulfill regulatory obligations to any agencies having jurisdiction, seek or obtain from a court of competent jurisdiction judgment on, confirmation, or vacation of an arbitration award, and may inform its lenders, Affiliates, auditors, attorneys, and insurers, and any Person providing it with financing, as necessary, under pledge of confidentiality and may consult with expert consultants as required in connection with an arbitration proceeding under pledge of confidentiality. If a Party seeks preliminary injunctive relief from any court to preserve the status quo or avoid irreparable harm pending arbitration, the Parties shall keep the court proceedings confidential to the maximum extent permitted by Applicable Laws and Regulations.

29.3.8 Preliminary Injunctive Relief. Nothing in this Article XXIX shall be construed to preclude the ability of any Party to resort to a court of competent jurisdiction solely for the purposes of securing a temporary or preliminary injunction to preserve the status quo or avoid irreparable harm pending arbitration. This Article 29.3.8 shall not be construed as a waiver of arbitration under Article 29.3.

29.4 FERC Jurisdiction Over Certain Disputes. Nothing in this Agreement shall be construed to preclude any Party from filing an application, petition or complaint with FERC with respect to any claim over which FERC has jurisdiction. In such case, the other Party may request that FERC decline to adjudicate such application, petition or complaint. If FERC declines to adjudicate such application, petition or complaint with respect to all or part of a claim, the portion of the claim not so accepted by FERC may be resolved through arbitration, as provided

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 54

in this Article XXIX. To the extent that FERC asserts or accepts jurisdiction over all or part of a claim, the decisions, findings of fact, or orders of FERC shall be final and binding, subject to judicial review under the Federal Power Act, and any arbitration proceedings that may have commenced prior to the assertion or acceptance of jurisdiction by FERC shall be stayed, pending the outcome of the FERC proceedings. The arbitrator shall have no authority to modify, and shall be conclusively bound by, any decisions, findings of fact, or orders of FERC; provided, however, that to the extent that any decisions, findings of fact, or orders of FERC do not provide a final or complete remedy to the Party seeking relief, such Party may proceed to arbitration under this Article XXIX to secure such a remedy, subject to any FERC decisions, findings, or orders.

29.5 Continued Performance. The Parties shall continue to perform their respective obligations under this Agreement during the pendency of any dispute including a dispute regarding the effectiveness of the purported termination of this Agreement.

Article XXX

MISCELLANEOUS

30.1 Partial Invalidity. Wherever possible, each provision of this Agreement shall be interpreted in a manner as to be effective and valid under Applicable Laws and Regulations, but if any provision contained herein shall be found to be invalid, illegal, or unenforceable in any respect and for any reason, such provision shall be ineffective to the extent, but only to the extent, of such invalidity, illegality, or unenforceability without invalidating the remainder of the provision or any provision of this Agreement, unless such a construction would be unreasonable. If such a construction would be unreasonable or would deprive a Party of a material benefit under this Agreement, the Parties shall seek to amend this Agreement to remove the invalid portion and otherwise provide the benefit, unless prohibited by Applicable Laws and Regulations.

30.2 Successors Included. Reference to any individual, corporation, or other entity shall be deemed a reference to such individual, corporation, or other entity together with its successors and permitted assigns from time to time.

30.3 Applicable Laws and Regulations. This Agreement is made subject to all existing and future Applicable Laws and Regulations, and to all existing and future duly promulgated orders or other duly authorized actions of Governmental Authorities having jurisdiction over the matters set forth in this Agreement.

30.4 Choice of Law and Jurisdiction. The interpretation and performance of this Agreement shall be in accordance with the laws of the State of New Mexico, without regard to choice of law or conflict of laws principles that would require the application of the laws of a different jurisdiction.

30.5 Entire Agreement. This Agreement supersedes all previous representations, understandings, negotiations, and agreements either written or oral between the Parties or their representatives with respect to the subject matter hereof, and constitutes the entire agreement of the Parties with respect to the subject matter hereof. In the event of any inconsistency between the main body of

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 55

this Agreement and the Appendices attached hereto and made a part hereof, the main body of this Agreement shall control.

30.6 Counterparts to this Agreement. This Agreement may be executed in any number of counterparts, each of which shall be an original, but all of which together shall constitute one and the same instrument.

30.7 Amendments. No amendments or changes to this Agreement shall be binding unless made in writing and duly executed by the Parties and accepted or approved by the FERC. Notwithstanding any provisions in this Agreement to the contrary, Generator may exercise its rights under Sections 205 and 206 of the Federal Power Act and pursuant to FERC’s rules and regulations promulgated thereunder with respect to any rate, term, condition, charge, classification of service, rule or regulation for any services provided under this Agreement over which FERC has jurisdiction. Notwithstanding any provisions in this Agreement to the contrary, EPE may unilaterally make application to the FERC under Section 205 of the Federal Power Act and pursuant to FERC’s rules and regulations promulgated thereunder for a change in any rate, term, condition, charge, classification of service, rule or regulation under or related to this Agreement.

30.8 Amendments Included. Reference to, and the definition of, any document (including this Agreement) shall be deemed a reference to such document as it may be amended, amended and restated, supplemented, or modified from time to time.

30.9 Notices. Unless otherwise provided in this Agreement, any notice, consent, or other communication required to be made under this Agreement shall be in writing and shall be delivered in person, by certified mail (postage prepaid, return receipt requested), or by nationally recognized overnight courier (charges prepaid), in each case properly addressed to such Party as shown below, or sent by facsimile transmission to the facsimile number indicated below. Any Party may from time to time change its address for the purposes of notices, consents, or other communications to that Party by a similar notice specifying a new address, but no such change shall become effective until it is actually received by the Party sought to be charged with its contents. All notices, consents, or other communications required or permitted under this Agreement that are addressed as provided in this Article 30.9 shall be deemed to have been given (a) upon delivery if delivered in person, by overnight courier or certified mail or (b) upon automatically generated confirmation if given by facsimile.

Generator:

Senior Vice President

Bulk Marketing and Development

Public Service Company of New Mexico

2401 Aztec Road, NE

Albuquerque, New Mexico 87107

Tel:    505-855-6250

Fax:    505-855-6368

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 56

El Paso Electric Company:

Assistant Vice President, System Operations

El Paso Electric Company

123 W. Mills

El Paso, Texas 79901

Tel:    915-543-5711

Fax:    915-521-4763

Operating Agent:

Assistant Vice President, System Operations

El Paso Electric Company

123 W. Mills

El Paso, Texas 79901

Tel:    915-543-5711

Fax:    915-521-4763

30.10 Waivers. The failure of any Party to enforce at any time any provision of this Agreement shall not be construed as a waiver of such provision. Nor shall such Party’s failure to enforce a provision affect in any way the validity of this Agreement or any portion thereof or the right of a Party thereafter to enforce each and every provision of this Agreement. To be effective, a waiver under this Agreement must be in writing and specifically state that it is a waiver. No waiver of any breach of this Agreement shall be held to constitute a waiver of any other or subsequent breach.

30.11 No Third Party Beneficiaries. Except as provided in Article IX with respect to the WSCC for express purposes set forth in Article IX, nothing in this Agreement, whether express or implied, is intended to confer any rights or remedies under or by reason of this Agreement on any Persons other than the Parties and their respective permitted successors and assigns.

30.12 Further Assurances. If any Party determines in its reasonable discretion that any further instruments, assurances, or other things are necessary or desirable to carry out the terms of this Agreement, the other Party shall execute and deliver all such instruments or assurances, and do all things reasonably necessary or desirable to carry out the terms of this Agreement. Without limiting the generality of the foregoing, EPE agrees, at Generator’s expense and upon Generator’s request, to prepare and/or provide such information in connection with this Agreement and/or the services to be provided under this Agreement as may be reasonably required by any potential lender to Generator.

30.13 Headings. The headings contained in this Agreement are solely for the convenience of the Parties and shall not be used or relied upon in any manner in the construction or interpretation of this Agreement.

30.14 Articles. Unless otherwise specified, all references in this Agreement to numbered articles shall be to numbered articles in this Agreement.

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 57

30.15 Number, Gender, and Inclusion. Defined terms in the singular shall include the plural and vice versa, and the masculine, feminine, or neuter gender shall include all genders. Whenever the words “include,” “includes,” or “including” are used in this Agreement, they are not limiting, and have the meaning as if followed by the words “without limitation.”

30.16 Good Utility Practice. The Parties shall discharge any and all obligations under this Agreement in accordance with Good Utility Practice.

30.17 Succession Upon Membership in an RTO. If the Operating Agent joins an RTO, the terms and conditions provided in this Agreement for interconnection with the EPE Transmission System at the Afton Switching Station shall be superseded by any pertinent interconnection and operational provisions required by the RTO, and the Parties shall amend this Agreement as necessary to conform with RTO requirements. Additionally, if a change in the Operating Agent occurs under an RTO, the Parties shall amend this Agreement to reflect such change.

30.18 Notification of Change of Operating Agent. The Operating Agent will provide the other Party with advanced written notice of a change in the identity of the Operating Agent.

30.19 Amended and Restated. The Interconnection Agreement is hereby amended and restated in its entirety as set forth in this Agreement.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date set forth at the beginning of this Agreement.

PUBLIC SERVICE COMPANY OF NEW MEXICO
By:	/s/ ROGER FLYNN
Title:	Executive Vice President & Chief Operating Officer
EL PASO ELECTRIC COMPANY (INCLUDING IN ITS CAPACITY AS OPERATING AGENT)
By:	/s/ JOHN A. WHITACRE
Title:	Vice President - Transmission & Distribution

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 58

Appendix A

Equipment to be Installed for Generator Interconnection Facilities

Appendix B

Equipment to be Installed for EPE Interconnection Facilities & Interconnection System Upgrades

Appendix C

EPE’s and Generator’s Construction and Testing Schedule

Appendix D

Metering, Relay, and Communication Equipment

Appendix E

Interconnection Drawing and One-line and Schematics

Appendix F

Afton Plot Map

First Amended and Restated Interconnection Agreement between El Paso Electric Company and Public Service Company of New Mexico 59

APPENDIX A

EQUIPMENT TO BE INSTALLED

FOR GENERATOR INTERCONNECTION FACILITIES

PHASE I

The Afton Power Project Phase I consists of a simple cycle turbine for peaking application and common facilities configured to allow for immediate expansion to a combined cycle facility. The comprehensive design is based on interconnection studies that have been completed for the existing combustion turbine. The unit is being designed to current utility industry standards. Certain items below are subject to bid change, field change, and manufacturer’s change but represent final design as of the date of execution of this Agreement. The equipment provided for the Facility is being designed to Generator design criteria.

The following major items are to be installed, as defined in the Agreement, as Generator’s Interconnection Facilities:

• GE 18 kV generator low side breaker, synchronizing systems, relay and protective systems;

• Waukesha 208 MVA 18kV: 345 kV autotransformer, three phase;

• Interconnecting Isophase Al buss, PT’s, CT’s;

• Steel reinforced concrete civil/foundation structures, conduit and cable trench as required, control and power cables, grounding and lightning protection system; and

• Interconnection to EPE communication equipment, interconnection to switchyard communication and control equipment.

APPENDIX B

EQUIPMENT TO BE INSTALLED FOR EPE INTERCONNECTION FACILITIES AND

INTERCONNECTION SYSTEM UPGRADES

EPE Interconnection Facilities and Interconnection System Upgrades.

The Afton Switchyard is configured for an ultimate arrangement of four (4) bays arranged in a breaker and a half arrangement. This ultimate arrangement can accommodate four (4) 345 kV lines and three (3) generator connections. One breaker position will be a spare position. The initial switchyard installation will be two (2) bays arranged in breaker and a half arrangement. This initial arrangement will provide connections for two (2) 345 kV lines and two (2) generators. The switchyard is being designed using EPE standards.

The Afton 345kV Switchyard will be connected to El Paso Electric Company’s (EPE) Luna to Newman 345kV Line by the construction of two (2) parallel single circuit transmission lines (approximately 0.5 miles each) called the Afton to Luna line No. 1 and the Afton to Newman Line.

Each line will consist of three (3) phases using two (2) 795 kcmil, 45/7 strands ACSR code word “Tern” per phase and two (2) 3/8” EHS, 7 strands galvanized steel overhead shieldwires. One shieldwire will carry integral fiber optic communications cable.

The conductors and shieldwires will be supported using direct embedded H-Frame tangent structures and single pole angle guyed tubular steel pole structures.

Connection to the existing EPE Luna to Newman Line will be by means of a flying tap configuration. The new transmission lines will be insolated from each other by installing a self-supporting steel pole Deadend structure with drilled pier type foundations in the existing EPE Luna to Newman right of way.

The equipment being provided for the Switchyard was purchased using EPE specifications, as follows:

• Six (6) circuit breakers rated 362 kV, 1300 kV BIL, 2000 Amp, 40 kA interrupting rating. The breakers are provided with bushing current transformers and standard factory control cabinets. These breakers are being provided by GE-Hitachi HVB, Inc.

• Fourteen (14) 345 kV disconnect switches rated 362 kV, 1300 kV BIL, 2000 Amp, 100 kA withstand capability. Two of the switches are being provided with grounding switches. These switches are Pascor Atlantic switches.

• Fourteen (14) capacitor voltage transformers (CVT) rated 345 kV, 1300 kV BIL, with a ratio of 1800/3000 to 1. The CVT’s accuracy classification is 0.3MWXYZ, ZZ. The CVT’s are being provided by Trench Limited.

• Twelve (12) total current transformers (CT) as follows:

• Six (6) current transformers (CT) rated 345kV, 1300kV BIL, with a ratio of 2000:5 AMR. The CT’s accuracy classification is 0.3B1.8.

• Three (3) current transformers (CT) rated 345kV, 1300kV BIL, with a ratio of 300:5 A. The CT’s accuracy classification is 0.15B1.8 and have an extended range to provide metering accuracy for the plant auxiliary loads as well as plant generation.

• Three (3) current transformers (CT) rated 345kV, 1300kV BIL, with a ratio of 500:5 A. The CT’s accuracy classification is 0.15B1.8. The CT’s are being provided by Trench Limited.

• Structural Steel for transmission line dead ends and equipment supports.

• DC system including batteries, battery rack, charger and panel boards. The DC system will be rated 125 volts.

• 120/208 volt AC auxiliary system including transformers, automatic transfer switch and panel boards.

• Control building for housing the 125 v DC system and the 120/208 v AC system and the protective relay panels.

• Protective relay and control panels for line and bus protection. Ten (10) line protection and control panels and two (2) bus protection and control panels will be included. The protective relay and control panels will be designed to EPE standards. The panels include redundant revenue metering equipment. EPE designed and provided six (6) transmission line protective relay panels.

• Conduit and cable trench.

• Control and power cable.

• Grounding system consisting of cable, ground rods and connections to equipment.

• Lightning protection system consisting of shield wires connected to the transmission line dead ends.

• Switchyard bus rated 2000 amp. The bus will consist of aluminum tube and ACSR conductor.

• Lightning system mounted on the switchyard steel structures.

• Bus support insulators.

• Crushed rock for covering the switchyard.

• Switchyard fence.

• Interconnection to EPE communications equipment.

• Interconnection to the Generators plant equipment.

• Costs associated with transfer of a portion of the BLM 102630 R-O-W

Total cost of EPE Interconnection Facilities and Interconnection System Upgrades, including installation, labor and overheads:

$8,539,351.82 (per Generator accounting records as of June 3, 2003)

To allocate the $8,539,351.82 into EPE Interconnection Facilities Costs and Interconnection System Upgrade Costs, a detailed estimate of the costs of the facilities between the Interconnection Point and Generator’s side of air switch 32485 was obtained from the two primary contractors. The resulting estimate of $400,016.38 represents the cost of the EPE Interconnection Facilities. The cost of the Interconnection System Upgrades is equal to the remaining amount of $8,139,335.44.

First Amended and Restated

Interconnection Agreement between

El Paso Electric Company and

Public Service Company of New Mexico

EPE Interconnection Facilities Costs

EPE Interconnection Facilities

	Steel and Apparatus
12,198.00	High Switch Support Stand
54,947.00	Single Bay Dead End Tower at Generator Step Up Transformer
68,072.50	50% of Double Bay Dead End Tower in Afton Switchyard
47,925.00	Current Transformer (3 – single phase, ratio: 300:5, accuracy: 0.15B1.8)
28,288.00	Disconnect Switch at Generator Step Up Transformer
$211,430.50	Subtotal Steel and Apparatus *
	Installation, Labor, Hardware, Grounding, Foundations, Appurtenances
60,869.50	50% of Double Bay Deadend in Afton Switchyard
21,422.00	Conductor & Static between Deadend Towers
71,216.00	Single Bay Deadend at Generator Step up Transformer
	Subtotal Installation, Labor, Hardware, Grounding, Foundations,
$153,507.50	Appurtenances **
$364,938.00	Total Direct Costs Associated with EPE Interconnection Facilities
$35,078.38	Overhead Costs (ratably allocated)
$400,016.38	Total EPE Interconnection Facilities (radial facilities)

EPE Interconnection Facilities costs are broken down into a listing for steel and apparatus and for the associated costs of installation, labor, hardware, grounding, foundations, appurtenances required to put the steel and apparatus into service.

* allocation of costs to EPE Interconnection Facilities per estimate provided by Power Engineers

** allocation of costs to EPE Interconnection Facilities per estimate provided by Great Southwestern

Interconnection System Upgrade Costs

Interconnection System Upgrades

	Total Direct Costs associated with Interconnection System
$7,425,577.93	Upgrades
$713,757.51	Overhead Costs (ratably allocated)
$8,139,335.44	(a) Total Interconnection System Upgrades (network upgrades)

Note: The dollar values and allocations in this Appendix B were provided by Generator as of June 3, 2003 and are subject to audit by EPE in accordance with Article 7.1.3.

First Amended and Restated

Interconnection Agreement between

El Paso Electric Company and

Public Service Company of New Mexico

APPENDIX C

EPE’S AND GENERATOR’S CONSTRUCTION AND TESTING SCHEDULE

As of the Effective Date of this Agreement the Parties have completed the construction and testing schedule.

First Amended and Restated

Interconnection Agreement between

El Paso Electric Company and

Public Service Company of New Mexico

EX-23.01

EXHIBIT 23.01

CONSENT OF INDEPENDENT AUDITORS

The Board of Directors

El Paso Electric Company:

We consent to the incorporation by reference in the registration statements (Nos. 333-17971 and 333-82129) on Form S-8 of El Paso Electric Company of our report dated March 10, 2004, relating to the consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2003 and 2002 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, 2003, which report appears in the December 31, 2003 annual report on Form 10-K of El Paso Electric Company. Our report refers to a change in the Company’s method of accounting for asset retirement obligations in 2003.

KPMG LLP

El Paso, Texas

March 12, 2004

107

EX-24.02

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

CERTIFICATE OF RESOLUTION

I, Raul A. Carrillo, Jr., Senior Vice President, General Counsel and Corporate Secretary of El Paso Electric Company, a Texas corporation (the “Company”), do hereby certify that attached hereto is a true, correct and complete copy of the resolution authorizing signatures pursuant to the Power of Attorney for the 2003 Form 10-K, duly adopted by the Board of Directors of the Company at a meeting of said Board duly convened and held on February 5, 2004.

IN WITNESS WHEREOF, I have set my hand and have affixed the seal of the Company on this 15th day of March, 2004.

By:	/s/    RAUL A. CARRILLO, JR.
	Raul A. Carrillo, Jr. Senior Vice President, General Counsel and Corporate Secretary

(Corporate Seal)

EXHIBIT 24.02

EL PASO ELECTRIC COMPANY

RESOLUTION TO THE BOARD OF DIRECTORS

FEBRUARY 5, 2004

RESOLVED, that Gary R. Hedrick, Terry Bassham, J. Frank Bates and Raul A. Carrillo, Jr. are each hereby duly appointed the Company’s, and its Officers’ and Directors’, true and lawful attorneys-in-fact and agents, for its place and stead, in any and all capacities, with full power to act alone, to sign the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 (the “2003 Form 10-K”), and in any and all amendments thereto, and to file such 2003 Form 10-K and any such amendment, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto each of the said attorneys-in-fact and agents, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

EX-31.01

Exhibit 31.01

CERTIFICATIONS

I, Gary R. Hedrick, President and Chief Executive Officer, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) [Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986]

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely

affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 15, 2004

EL PASO ELECTRIC COMPANY
By:	/s/    GARY R. HEDRICK
	Gary R. Hedrick President and Chief Executive Officer (Principal Executive Officer)

I, Terry Bassham, Executive Vice President, Chief Financial and Administrative Officer, certify that:

1. I have reviewed this annual report on Form 10-K of El Paso Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) [Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986]

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely

affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: March 15, 2004

EL PASO ELECTRIC COMPANY
By:	/s/    TERRY BASSHAM
	Terry Bassham Executive Vice President, Chief Financial and Administrative Officer (Duly Authorized Officer and Principal Financial Officer)

EX-32.01

Exhibit 32.01

March 15, 2004

The certification set forth below is being submitted in connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2003 (the “Report”) of El Paso Electric Company (the “Company”) for the purpose of complying with Rule 13a-14(b) or Rule 15d-14(b) of the Securities Exchange Act of 1934 (the “Exchange Act”) and Section 1350 of Chapter 63 of Title 18 of the United States Code.

Gary R. Hedrick, the President and Chief Executive Officer and Terry Bassham, the Executive Vice President, Chief Financial and Administrative Officer of the Company, each certifies that, to the best of his knowledge:

1. such Report fully complies with the requirements of Section 13(a) of the Exchange Act; and

2. the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/    GARY R. HEDRICK        

Gary R. Hedrick

President and Chief Executive

Officer

/s/    TERRY BASSHAM        

Terry Bassham

Executive Vice President, Chief

Financial and Administrative Officer