Edgar Filing: EL PASO ELECTRIC CO /TX/

Form 10-K

Index to Financial Statements

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, 2005

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

For the transition period from to

Commission file number 0-296

El Paso Electric Company

(Exact name of registrant as specified in its charter)


Texas		74-0607870
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Stanton Tower, 100 North Stanton, El Paso, Texas		79901
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (915) 543-5711

Securities Registered Pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, No Par Value		New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES x NO ¨

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO x

As of June 30, 2005, the aggregate market value of the voting stock held by non-affiliates of the registrant was $966,881,746 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2006, there were 48,239,611 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 2006 annual meeting of its shareholders are incorporated by reference into Part III of this report.

Index to Financial Statements

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
City Rate Agreement		Rate Agreement dated July 21, 2005, between the Company and the City of El Paso providing for, among other things, most retail base rates to remain at their current levels until June 30, 2010
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 remained frozen pursuant to the Texas Rate Stipulation
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MW		Megawatt(s)
MWh		Megawatt-hour(s)
NMPRC		New Mexico Public Regulation Commission
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 dated April 27, 2004 between the Company and all other parties to the Company’s rate proceedings before the New Mexico Commission providing for, among other things, a three-year freeze on base rates after an initial 1% reduction
New Texas Freeze Period		Five-year period beginning July 1, 2005, during which base rates for most Texas retail customers remain frozen pursuant to the City Rate Agreement
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 dated November 1, 2001, 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 dated August 30, 1995, 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 dated March 25, 1999, 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)

Index to Financial Statements

TABLE OF CONTENTS


Item	Description	Page
PART I
1	Business	1
1A	Risk Factors	21
1B	Unresolved Staff Comments	23
2	Properties	25
3	Legal Proceedings	25
4	Submission of Matters to a Vote of Security Holders	26

PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities	27
6	Selected Financial Data	28
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
7A	Quantitative and Qualitative Disclosures About Market Risk	47
8	Financial Statements and Supplementary Data	50
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	116
9A	Controls and Procedures	116
9B	Other Information	116

PART III
10	Directors and Executive Officers of the Registrant	117
11	Executive Compensation	117
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	117
13	Certain Relationships and Related Transactions	118
14	Principal Accounting Fees and Services	118

PART IV
15	Exhibits and Financial Statement Schedules	118

(ii)

Index to Financial Statements

FORWARD-LOOKING STATEMENTS

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

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capital expenditures,

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earnings,

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liquidity and capital resources,

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litigation,

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accounting matters,

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possible corporate restructurings, acquisitions and dispositions,

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compliance with debt and other restrictive covenants,

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interest rates and dividends,

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environmental matters,

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nuclear operations, and

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the overall economy of our service area.

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

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our rates following the end of the New Texas Freeze Period ending June 30, 2010 and the New Mexico Stipulation,

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

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increased costs at Palo Verde,

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reductions in output at generation plants including Palo Verde,

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unscheduled outages including outages at Palo Verde,

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electric utility deregulation or re-regulation,

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regulated and competitive markets,

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ongoing municipal, state and federal activities,

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economic and capital market conditions,

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changes in accounting requirements and other accounting matters,

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changing weather trends,

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

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the impact of changes and downturns in the energy industry and the market for trading wholesale electricity,

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approval by the Texas Commission of the 75% off-system sales margin retention percentage as contemplated in the City Rate Agreement,

(iii)

Index to Financial Statements

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the City of El Paso’s review of operating expenses pursuant to the City Rate Agreement,

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political, legislative, judicial and regulatory developments,

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the impact of lawsuits filed against us,

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the impact of changes in interest rates,

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

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

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

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homeland security considerations,

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

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other circumstances affecting anticipated operations, sales and costs.

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

(iv)

Index to Financial Statements

PART I

Item 1.

Business

General

El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a wholesale customer 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, 2005, the Company’s energy sources consisted of approximately 46% nuclear fuel, 30% natural gas, 9% coal, 15% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 341,000 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 60% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2005). 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 January 31, 2006, the Company had approximately 1,000 employees, 30% of whom are covered by a collective bargaining agreement. The existing collective bargaining agreement with these employees expires in June 2006 and the Company anticipates entering into negotiations on a new collective bargaining agreement in the second quarter of 2006. In addition, the Company is presently conducting collective bargaining negotiations with an additional 144 employees from the Company’s meter reading and collections area, facilities services area and customer service area who voted for union representation in 2003 and 2004.

The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov.

Index to Financial Statements

Facilities

The Company’s net installed generating capacity of 1,501 MW consists of the following:


Station	Primary Fuel Type	Nameplate Capacity Entitlement
Palo Verde Station	Nuclear Fuel	600 MW
Newman Power Station	Natural Gas	482 MW
Rio Grande Power Station	Natural Gas	246 MW
Four Corners Station	Coal	104 MW
Copper Power Station	Natural Gas	68 MW
Hueco Mountain Wind Ranch	Wind	1 MW

Total		1,501 MW

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 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 maintain a minimum accumulation and a minimum funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company was above its minimum funding level as of December 31, 2005. 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.

Index to Financial Statements

Although the 2004 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. The 2007 study is expected to be complete in the second quarter of 2008. See “Disposal of Low-Level Radioactive Waste” below.

Historically, regulated utilities such as the Company have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning. The Company, through an affiliated transmission and distribution utility, will be able to continue to collect from customers the costs of decommissioning if and when it becomes subject to the Texas Restructuring Law. 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 2004 decommissioning study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2037. APS believes that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the term of its operating license.

Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the “Waste Act”), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde Participants. The DOE has previously reported that its spent nuclear fuel disposal facilities would not be in operation 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.

Index to Financial Statements

The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs are identified to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs. In December 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the DOE’s acceptance of spent fuel. 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. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.

Steam Generators. Because of 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 a cost to the Company of approximately $45.4 million. During 2005 Palo Verde completed the installation of new steam generators in Unit 1 at a cost to the Company of approximately $36.8 million. The steam generator replacements were based on analysis of the net economic benefit from expected improved performance of the respective units and the need to realize continued production from the units over their full licensed lives. The output from Palo Verde Unit 1 has been restricted to between 17 to 25% since the unit returned to service after replacement of the steam generators in December 2005. Output has been limited due to excess vibration in one of the shutdown cooling lines. APS has informed the Company that they are scheduling a one week outage in late March 2006 to install monitoring equipment in preparation for a 35-40 day outage beginning in June 2006 to modify the cooling line in an attempt to eliminate the excess vibration.

Typically, the Company realizes between 40% and 50% of its off-system sales margins during the first quarter of each calendar year when the Company’s native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from nuclear fuel resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. The Company estimates that the reduced output and upcoming outages at Palo Verde Unit 1, together with lower than originally forecast wholesale energy prices, will result in reduced off-system sales margins of approximately $12 to $18 million for the period January through July 2006. The Company cautions that results would differ from its estimates to the extent that actual market prices, Palo Verde Unit 1 operations and other factors vary from its assumptions. The adverse financial impact on the Company from continued reduced output and outages from Palo Verde Unit 1

Index to Financial Statements

could increase and would include foregone off-system sales margins, higher capital and/or operating costs and increased purchased power and other costs.

APS has identified accelerated degradation in the steam generator tubes in Unit 3 and plans to replace the steam generators at this unit in 2007. The eventual total project cash expenditures for steam generator replacements for Units 1, 2 and 3 are currently estimated to be $720.6 million in direct costs (the Company’s portion being $113.8 million). As of December 31, 2005, the Company has paid approximately $71.1 million of such costs. The Company expects its portion will be funded with internally generated cash. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview.”

Reactor Vessel Heads. In accordance with applicable NRC requirements, APS conducts regular inspections of reactor vessel heads at Palo Verde Units 1, 2 and 3. In an effort to reduce long-term operating costs at the station related to inspection of the reactor heads, related equipment, and possible repair costs, APS plans to replace reactor vessel heads at Palo Verde. Reactor vessel head replacement is scheduled to occur at Units 1, 2 and 3 in 2010, 2009 and 2009 respectively. The Company’s share of the costs for this project is estimated to be $21.3 million.

Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, the Company could be assessed retrospective premium adjustments. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $10 million per incident. Based upon the Company’s 15.8% interest in the three Palo Verde units, the Company’s maximum potential assessment per incident for all three units is approximately $47.9 million, with an annual payment limitation of approximately $4.7 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

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.

Index to Financial Statements

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

Copper Power Station

The Company’s Copper Power Station, located in El Paso, Texas, consists of a 68 MW combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas but can also operate on fuel oil.

Hueco Mountain Wind Ranch

The Company’s Hueco Mountain Wind Ranch, located in Hudspeth County, east of El Paso County and adjacent to Horizon City, currently consists of two wind turbines with a total capacity of 1.32 MW of which a portion, currently 27%, can be used as net capability for resource planning purposes.

Transmission and Distribution Lines and Agreements

The Company owns or has significant ownership interests in four major 345 kV transmission lines in New Mexico, three 500 kV lines in Arizona, and owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability 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 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

Index to Financial Statements

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 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. The Afton Substation interconnects a generator owned and operated by PNM.

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. The Company owns 66.7% of the terminal. 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 Jojoba Substation, then to the Kyrene Substation located near Tempe, Arizona. These lines provide the Company with a transmission path for delivery of power from Palo Verde. The Company also owns 18.7% of two 500 kV switchyards connected to the Palo Verde-Kyrene 500 kV line: the Hassayampa switchyard adjacent to the southern edge of the Palo Verde 500 kV switchyard and the Jojoba switchyard approximately 24 miles from Palo Verde. These switchyards were built to accommodate the addition of new generation and transmission in the Palo Verde area.

Environmental Matters

The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. If the United States regulates green house gas emissions, the Company’s fossil fuel generation assets will be faced with the additional cost of monitoring, controlling and reporting these emissions. Because a significant portion of the Company’s generation assets is nuclear and gas fired, the Company does not believe such regulations would impose greater burdens on the Company than on most other electric utilities. In addition, unauthorized releases of pollutants or contaminants into the environment

Index to Financial Statements

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 $2.1 million as of December 31, 2005, 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.

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

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

Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems and the cost of capital improvements and replacements at Palo Verde, including the fabrication and installation of Palo Verde Unit 3 steam generator and reactor head vessel replacements for all three units at Palo Verde. Replacement power costs expected to be incurred during the replacement of Palo Verde steam generators are not included in construction costs. Studies indicate that the Company will need additional resources to meet increasing load requirements on its system which are included in the table below.

Index to Financial Statements

The Company’s estimated cash construction costs for 2006 through 2009 are approximately $583 million. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.


By Year (1)(2) (In millions)			By Function (In millions)

2006	$	97	Production (1)(2)	$	316
2007		131	Transmission		30
2008		155	Distribution		184
2009		200	General		53

Total	$	583	Total	$	583

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

(2)	Includes $177 million for local generation, $19 million for the Four Corners Station and $120 million for the Palo Verde Station.

Energy Sources

General

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

Power Source


	Years Ended December 31,
	2005		2004		2003
Nuclear fuel	46	%	49	%	50	%
Natural gas	30		27		27
Coal	9		8		9
Purchased power	15		16		14

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 Commission and the NMPRC. See “Regulation – Texas Regulatory Matters” and “– New Mexico Regulatory Matters.”

Nuclear Fuel

The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride (“conversion services”); the enrichment of uranium hexafluoride (“enrichment services”); the fabrication of fuel assemblies (“fabrication services”); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. The Palo Verde Participants have contracts in place that will furnish 100% of Palo Verde’s operational requirements for uranium concentrates, conversion services and enrichment services through 2008. Such contracts could also provide 100% of

Index to Financial Statements

enrichment services in 2009 and 2010. The Palo Verde Participants have a contract that will provide 100% of fabrication services until at least 2015 for each Palo Verde unit.

Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The 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. During the term of the agreement, the revolving credit facility may be increased to $150 million. This facility was renewed in 2004 for a five-year term ending December 17, 2009. At December 31, 2005, approximately $41.9 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. The Company may request a release and return of the collateral provided that the Company maintains certain credit ratings and meets other conditions. In the Company’s financial statements, the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company.

Natural Gas

The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2005, 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 and it is expected to continue in 2006. Interstate gas is delivered under a base firm transportation contract. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the 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 is 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. The Four Corners coal contract expires in 2016 which coincides with the term of the Four Corners Plant lease with the Navajo Nation. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plant’s operational requirements for its useful life.

In the third quarter of 2005, upon participant approval of a 2004 study conducted by an outside engineering firm, the Company decreased its estimated final reclamation and coal mine closure liability related to the Company’s interest in Four Corners from $10.5 million to $9.6 million. The $0.9 million pre-tax decrease resulted in a $0.7 million credit to energy expense and a $0.2 million decrease in regulatory assets.

Index to Financial Statements

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 2005 under a purchase agreement that terminated December 31, 2005. This agreement included a demand, energy and a transmission charge. In 2004, the Company entered into a 20-year contract, beginning in 2006, for the purchase of up to 133 MW of capacity and associated energy from SPS. This contract includes a demand charge, energy charge and a transmission charge. Other purchases of shorter duration were made during 2005 primarily to replace the Company’s generation resources during planned and unplanned outages. The Company entered into a power purchase and power sales contract with Phelps Dodge Energy Services, LLC (“PDES”) in December 2005 in which the Company will purchase 100 MW of energy from PDES at the Luna Substation near Deming, New Mexico and the Company will sell 100 MW of energy to PDES at the Greenlee Substation near Duncan, Arizona. After obtaining any necessary FERC approvals, the power sales will commence after the commercial operation date of the Luna Energy Facility expected in early 2006 and has an initial 15 year term. The exchange of energy allows the Company and PDES to obtain energy at locations near their load requirements. The Company will receive an energy purchase and sale exchange fee beginning in 2007.

Index to Financial Statements

Operating Statistics


	Years Ended December 31,
	2005			2004			2003
Operating revenues (in thousands):
Base revenues:
Retail:
Residential	$	183,667		$	174,752		$	171,459
Commercial and industrial, small		167,241			165,760			165,434
Commercial and industrial, large		41,321			43,150			43,294
Sales to public authorities		73,677			72,720			73,136

Total retail base revenues (1)		465,906			456,382			453,323
Wholesale:
Sales for resale		1,687			1,675			3,223

Total base revenues		467,593			458,057			456,546
Fuel Revenues:
Recovered from customer during the period		164,500			143,692			135,956
Change in deferred fuel revenues		79,539			17,360			(13,195	)

Total fuel revenues		244,039			161,052			122,761
Off-system sales		78,209			78,533			76,536
Other		14,072			10,986			8,519

Total operating revenues	$	803,913		$	708,628		$	664,362

Number of customers (end of year):
Residential		304,031			296,435			289,179
Commercial and industrial, small		31,969			31,079			30,254
Commercial and industrial, large		61			58			63	(2)
Other		4,792			4,553			4,524

Total		340,853			332,125			324,020

Average annual kWh use per residential customer		6,936			6,769			6,761

Energy supplied, net, kWh (in thousands):
Generated		7,500,144			7,611,455			7,740,923
Purchased and interchanged		1,258,469			1,410,114			1,250,707

Total		8,758,613			9,021,569			8,991,630

Energy sales, kWh (in thousands):
Retail:
Residential		2,090,098			1,986,085			1,932,171
Commercial and industrial, small		2,126,918			2,115,822			2,096,860
Commercial and industrial, large		1,165,506			1,236,426			1,197,065
Sales to public authorities		1,270,116			1,243,003			1,224,349

Total retail		6,652,638			6,581,336			6,450,445

Wholesale:
Sales for resale		41,883			41,094			67,754
Off-system sales		1,420,778			1,838,467			1,920,882

Total wholesale		1,462,661			1,879,561			1,988,636

Total energy sales		8,115,299			8,460,897			8,439,081
Losses and Company use		643,314			560,672			552,549

Total		8,758,613			9,021,569			8,991,630

Native system:
Peak load, kW		1,376,000			1,332,000			1,308,000
Net generating capacity for peak, kW		1,500,000			1,500,000			1,500,000

Total system:
Peak load, kW (3)		1,628,000			1,575,000			1,546,000
Net generating capacity for peak, kW (4)		1,500,000			1,500,000			1,500,000
System capacity factor (5)		57.8	%		60.1	%		60.1	%

(1)	Includes fuel recovered through New Mexico base rates of $29.4 million, $28.0 million and $27.4 million for 2005, 2004, and 2003, respectively.

(2)	Revised to conform with new 2004 large commercial and industrial billing system which counts customers by service location rather than by meter. This change did not affect sales or revenues of the Company.

(3)	Includes spot firm sales and net losses of 252,000 kW, 243,000 kW and 360,000 kW for 2005, 2004 and 2003, respectively.

(4)	Excludes 103,000 kW of firm on and off-peak purchases for 2005, 2004 and 2003.

(5)	System capacity factor includes average firm system purchases of 103,000 kW for 2005, 2004 and 2003.

Index to Financial Statements

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 was exempt from the requirements of the Texas Restructuring Law, including utility restructuring and retail competition until the expiration of the original Texas Freeze Period, which occurred in August 2005. The Texas Commission adopted a rule that further delays competition in the Company’s Texas service territory until at least the time that an independent regional transmission organization (“RTO”) begins operation in its relevant power markets. 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 effect electric restructuring will have on the Company should it be required to ultimately implement 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 and Enron engaged in misconduct and, if so, to determine potential remedies. The Company reached settlements with the FERC and other parties in 2002 and 2003. The Company believes the FERC’s order approving the settlement resolved all issues between the FERC and the other parties to this investigation. Under the settlements, the Company agreed to refund $15.5 million and 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 allowed the Company to sell power into wholesale markets at its incremental cost plus $21.11 per MWh. To the extent that wholesale market prices exceeded these agreed upon amounts, the Company lost the opportunity to realize these additional revenues. This provision did not have a significant impact on the Company’s revenues through December 31, 2004. The Company’s ability to make wholesale sales pursuant to its market-based rate authority was restored on January 1, 2005.

RTOs. FERC’s rule (“Order 2000”) on 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. A WestConnect Memorandum of Understanding (“MOU”), replacing the October 2, 2001 MOU, was signed by the Company and nine other transmission owners on December 6, 2004. On November 21, 2005 an eleventh member joined. This MOU obligates the parties to participate in and commit resources to ongoing joint efforts, including involvement with stakeholders, customers, local, state and federal regulatory personnel, and other Western Grid transmission providers to identify, develop and implement cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the Western Grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure.

Index to Financial Statements

The Company, however, is approximately a 7% participant in WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years. The establishment of an independent RTO in the Company’s service area is a prerequisite for the Company to be considered part of a Qualified Power Region as defined in the Texas Restructuring Law. The timing of the operations of WestConnect will affect when and whether the Company’s Texas service territory is deregulated under the Texas Restructuring Law.

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 grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.

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 (“City”). 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 and retail service activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. 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. On October 13, 2004, the Texas Commission approved a rule further delaying retail competition in the Company’s Texas service territory. The rule approved by the Texas Commission sets a schedule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of an RTO in the area that includes the Company’s service territory, including the development of retail market protocols to facilitate retail competition. The complete transition to retail competition would occur upon the completion of the last milestone, which would be the Texas Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes that adoption of this rule will likely delay retail competition in El Paso for a number of years. There is substantial uncertainty about both the regulatory framework and market

Index to Financial Statements

conditions that will exist if and when retail competition is implemented in the Company’s service territory, and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect the future operations, cash flows and financial condition of the Company.

Renewables and Energy Efficiency Programs. Notwithstanding the Texas Commission’s approval of a rule further delaying competition in the Company’s Texas service territory, the Company became subject to the renewable energy and energy efficiency requirements of the Texas Restructuring Law on January 1, 2006. Under the renewable energy requirements, the Company will have to annually obtain its pro rata share of renewable energy credits as determined by the Program Administrator (the Electric Reliability Council of Texas) appointed by the Texas Commission, based on total Texas retail sales subject to renewable energy credit allocation. During the 2005 session of the Texas Legislature, the statewide obligation to increase renewable energy capacity was raised from an additional 2,000 MW by 2009 to an additional 5,000 MW of additional renewable generating capacity in Texas by 2015. The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company estimates that its Texas retail sales will represent approximately 2% of the total credit allocation through 2010. In addition, by January 1, 2007, the Company will be required to fund incentives for energy efficiency savings that will achieve the goal of meeting 5% of its growth in demand through energy efficiency savings. By January 1, 2008 and every year thereafter, that goal is 10% of the Company’s growth in demand through energy efficiency savings. Preparatory costs incurred by the Company to meet these requirements may not be recoverable in the Company’s Texas service territory during the New Texas Freeze Period which expires June 2010. Pursuant to the Company’s Energy Efficiency Plan filed with the Texas Commission, the Company estimates it will incur $4.4 million in costs through 2009 for incentive payments to achieve its energy efficiency goal.

New Texas Freeze Period and Franchise Agreement. On July 21, 2005, the Company entered into an agreement with the City, the City Rate Agreement, to extend its existing freeze period for an additional five years expiring June 30, 2010, the New Texas Freeze Period. Under the City Rate Agreement which became effective as of July 1, 2005, most retail base rates will remain at their current level for the next five years. If, during the term of the agreement, the Company’s return on equity falls below the bottom of a defined range, the Company has the right to initiate a rate case and seek an adjustment to base rates. If the Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The range is market-based, and at current rates, would be a range of approximately 8% to 12%.

Pursuant to the City Rate Agreement, the Company will share with its Texas customers 25% of off-system sales margins and wheeling revenues. Under the prior rate agreement, the Company shared 50% of off-system sales margins and wheeling revenues with Texas customers. The City Rate Agreement requires a variance to the substantive rules of the Texas Commission regarding the sharing of margins. The Company has sought Texas Commission approval in PUC Docket No. 32289 filed on January 17, 2006 of the margin sharing provisions of the agreement. If the Texas Commission does not approve the margin sharing provisions of the City Rate Agreement, the Company and the City have agreed to negotiate in good faith to amend the rate agreement to achieve a similar economic result to the

Index to Financial Statements

parties. The Company is unable to predict when or if the Texas Commission will approve such provisions. A Texas Commission decision is expected in the second quarter of 2006.

In addition, the Company has committed to spend at least 0.3% of its El Paso revenues on civic and charitable causes within the City. The Company and the City have agreed to engage at the Company’s expense the services of an independent consultant to review the reasonableness of certain operating expenses of the Company. If the consultant finds such expenses to be unreasonable, the parties will seek to negotiate an appropriate remedy. If the parties are unable to agree on a remedy, the agreement will terminate at the end of one year, and, thereafter, the Company would be subject to traditional rate regulation. The City has retained a consultant to conduct this review which is expected to be completed in the second quarter of 2006. Consistent with the prior rate agreement, the City Rate Agreement may also be reopened by the City in the event of a merger or change in control of the Company to seek rate reductions based on post-merger synergy savings.

The City also granted to the Company a new 25-year franchise which became effective August 2, 2005 and increased franchise fee payments from 2% to 3.25% of gross receipts earned within the City limits. The franchise governs the Company’s usage of City-owned property and the payment of franchise fees.

Fuel and Purchased Power Costs. Although the Company’s base rates are frozen under the City Rate Agreement, pursuant to Texas Commission rules and the City Rate Agreement, the Company’s fuel costs are passed through to its customers. In January and July of each year, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with providing electricity, seek recovery of past undercollections of fuel revenues, and refund past overcollections of fuel revenues. All such fuel revenue and expense activities are subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.

The Company reconciled its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001 in PUC Docket No. 26194, and on May 5, 2004, the Texas Commission issued its final order. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge due to 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. This disallowance was recorded as a reduction of fuel revenue during the fourth quarter of 2003. 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 period in which the imputed capacity charges were deemed to have been incurred, the $4.2 million of imputed capacity charges were therefore permanently disallowed and not recoverable from its Texas customers. The Texas Commission’s decision has been appealed by two parties and the Company, and the Company is unable to predict the ultimate outcome of the appeals.

Index to Financial Statements

No. 26194 during the period covered by this fuel reconciliation case. The Company believes that it has accounted for its purchased power costs during the reconciliation period covered by PUC Docket No. 30143 in a manner consistent with the Texas Commission’s decision in PUC Docket No. 26194. However, the Texas Commission is currently conducting a generic rulemaking proceeding to determine a statewide policy for the appropriate recovery mechanism for such capacity costs in purchased power contracts. There can be no assurance as to the outcome of the rulemaking and its potential impact on the Company with respect to fuel recovery in future reconciliation periods, including that in PUC Docket No. 30143. Additionally, intervenors in PUC Docket No. 30143 filed testimony disputing as much as $44 million of the requested fuel and purchased power costs. A stipulation resolving all issues in the fuel reconciliation was filed on January 27, 2006. The stipulation provides for a $9.0 million disallowance of the eligible fuel costs requested by the Company. The Company recorded a reserve including $1.5 million in the third quarter of 2005, sufficient to provide for the stipulated $9.0 million in fuel disallowances in PUC Docket No. 30143. The Texas Commission approved a final order on March 8, 2006 which was consistent with the stipulation.

On July 8, 2005, the Company filed a petition (PUC Docket No. 31332) with the Texas Commission to increase its fixed fuel factors and to surcharge under-recovered fuel costs as a result of higher natural gas prices. The Company requested an increase in its Texas jurisdiction fixed fuel factors of $30.6 million or 23% annually to reflect an average cost of natural gas of $7.28 per MMBtu. The Company also requested a fuel surcharge to recover over a twelve month period $28.2 million of fuel undercollections through the end of May 2005. On September 13, 2005, the Company amended its petition to seek additional fuel under-recoveries through August 2005 and requested that the total fuel under-recoveries of $53.6 million, including interest as of the end of the under-recovery period, be surcharged over a 24-month period. On September 14, 2005, the Company filed a unanimous stipulation to approve the requested fixed fuel factor and amended fuel surcharge. The fixed fuel factor and surcharge were implemented effective with billings in October 2005 and final approval from the Texas Commission was received in November 2005.

On January 5, 2006, the Company filed a petition (PUC Docket No. 32240) with the Texas Commission to increase its fixed fuel factors and to surcharge under-recovered fuel costs as a result of higher natural gas prices. The Company requested an increase in its Texas jurisdiction fixed fuel factors of $30.8 million or 16% annually to reflect an average cost of natural gas of $9.35 per MMBtu. The Company also requested a fuel surcharge to recover over a twelve month period approximately $34 million of fuel undercollections, including interest, for under-recoveries for the period September 2005 through November 2005. The requested fuel factor and fuel surcharge were placed into effect on an interim basis subject to refund effective with February 2006 bills to customers. The Company is currently negotiating with parties on a settlement to resolve this proceeding. Any settlement will be subject to final approval by the Texas Commission.

Index to Financial Statements

impact on the Company’s revenues and financial condition. Under the performance standards the Company has not earned a performance reward nor incurred a penalty for the 2005 reporting period. The Company has calculated the performance rewards for the reporting periods ending in 2004 and 2003 to be approximately $0.2 million and $0.8 million, respectively. The 2003 reward was included in the Texas fuel reconciliation in PUC Docket No. 30143, along with energy costs incurred and fuel revenues billed. The 2004 reward will be included along with energy costs incurred and fuel revenue 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.

In compliance with the Texas Commission’s final order in PUC Docket No. 20450, the Company made a payment in November 2004 in the amount of $5.8 million of Palo Verde performance rewards funds to El Paso County General Assistance Agency and Big Bend Community Center Committee, Inc. to assist low-income customers pay their utility bills. In further compliance with the Texas Commission’s order, the Company sought and received approval by the El Paso City Council on January 3, 2006 to remit to the City approximately $5.8 million in Palo Verde performance rewards funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers.

New Mexico Regulatory Matters

The rates and services of the Company are regulated in New Mexico by the NMPRC. The largest municipality in the Company’s New Mexico service area is the City of Las Cruces. The NMPRC has jurisdiction to review utility agreements with municipalities regarding utility rates and services in New Mexico. The decisions of the NMPRC are subject to judicial review.

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.

New Mexico Rate Stipulation. On June 1, 2004, the Company implemented new rates according to 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 not collected in base rates; (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; 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. By May 30, 2006, the Company must also make a New Mexico filing to set rates to be effective by June 1, 2007.

Index to Financial Statements

Fuel and purchased power costs. In April 2004, the NMPRC, as part of the New Mexico Stipulation, approved a fuel and purchased power cost adjustment clause. The Company will continue to recover fuel and purchased power costs in base rates in the amount of $0.01949 per kWh and continue the fuel and purchased power cost adjustment to recover 90% of the remaining fuel and purchased power costs. Fuel and purchased power costs associated with the remaining 10% of the Company’s jurisdictional retail sales in New Mexico are fixed at $0.021 per kWh.

On August 29, 2005, the Company filed the annual reconciliation of its Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) for the period June 1, 2004 through May 31, 2005 in compliance with the requirements of the NMPRC’s Final Order in NMPRC Case No. 03-00302-UT. The Company requested reconciliation of all its fuel and purchased power costs for this period, and requested recovery of $1.3 million for the New Mexico jurisdictional portion of purchased power capacity costs consistent with its interpretation of NMPRC rules. However, the Company has not recognized deferred fuel revenue through December 2005 to reflect recovery of these costs pending a final order in the case. Although a hearing date has not been established for this proceeding, the Company expects a final order in this case in the first half of 2006. While the Company believes that it has fully supported the recovery of all of its applicable fuel and purchased power costs, the Company cannot predict when or how the NMPRC will rule on this case. An adverse ruling by the NMPRC could have a material negative effect on the Company’s results of operations.

Renewables. The New Mexico Renewable Energy Act of 2004 requires that, by January 1, 2006, renewable energy comprise no less than 5% of the Company’s total retail sales to New Mexico customers. The requirement increases by 1% annually until January 1, 2011, when the renewable portfolio standard shall reach a level of 10% of the Company’s total retail sales to New Mexico customers and will remain fixed at such level thereafter. On September 1, 2005, the Company filed its Procurement Plan detailing its proposed actions to comply with the Renewable Energy Act.

The NMPRC approved the Company’s 2005 Annual Procurement Plan in December 2005 allowing the Company to (i) enter into a contract to purchase renewable energy certificates (“RECs”) for full requirements in 2006 and 2007 and approximately 50% of the Company’s requirements in 2008 through 2011 and (ii) to create a deferral, with carrying costs, to recover from customers up to $0.2 million for costs related to the issuance of a diversity RFP for renewable resources to meet the remaining requirements in the 2008 to 2011 timeframe and thereafter. Costs incurred by the Company to purchase RECs to meet the requirements of the New Mexico Renewable Energy Act are to be recovered through the fuel clause as purchased power costs from New Mexico customers pursuant to the Renewable Energy Act and the NMPRC’s rules. The NMPRC’s decision in this case has been appealed to the New Mexico Supreme Court by the New Mexico Industrial Energy Consumers. The Company is unable to predict what, if any, action the New Mexico Supreme Court may take in this proceeding.

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.

Index to Financial Statements

Power Sales Contracts

On November 3, 2005, the Company entered into a transaction for the sale of 25 MW to be supplied during the off-peak period in 2006, excluding the month of April. The Company has entered into additional sales contracts of shorter duration (three months or less).

Franchises and Significant Customers

City of El Paso Franchise

The Company’s largest franchise agreement is with the City. The franchise agreement includes a 3.25% annual franchise fee and allows the Company to utilize public rights-of-way necessary to serve its retail customers within the City. The franchise with the City extends through July 31, 2030.

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 $1.3 million per year) 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. The Company must provide the book values of the assets covered by this agreement as of December 31, 2005 to Las Cruces by July 31, 2006. 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 signed a contract with Ft. Bliss in December 1998 under which Ft. Bliss will take retail electric service from the Company through December 2008. In May 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. In March 2006, the Company signed a new contract, subject to regulatory approval, with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016.

Index to Financial Statements

Item 1A.

Risk Factors

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory, fuel prices, the performance of our customers and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Our Costs Could Increase or We Could Experience Reduced Revenues if

There are Problems at the Palo Verde Nuclear Generating Station

A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units total approximately 600 MW of generating capacity. Palo Verde represents approximately 40% of our available net generating capacity and represented approximately 46% of our available energy for the twelve months ended December 31, 2005. Palo Verde comprises 42% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. We face 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 Unit 3; (iii) the replacement of reactor vessel heads at the Palo Verde units; (iv) an extended outage of any of the Palo Verde units; (v) increases in estimates of decommissioning costs; (vi) the storage of radioactive waste, including spent nuclear fuel; (vii) prolonged reductions in generating output; (viii) insolvency of other Palo Verde Participants; and (ix) compliance with the various requirements and regulations governing commercial nuclear generating stations. At the same time, our retail base rates in Texas are effectively capped through June 2010. As a result, we cannot raise our base rates in Texas in the event of increases in non-fuel costs or loss of revenue unless our return on equity falls below the bottom of a market-based defined range in which the bottom of the range is approximately 8%. Additionally, should retail competition occur, there may be competitive pressure on our rates which could reduce profitability. We cannot assure that revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result of inflation, changes in tax laws or regulatory requirements, or other causes.

Typically, the Company realizes between 40% and 50% of its off-system sales margins during the first quarter of each calendar year when the Company’s native load is lower than at other times of the years, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from nuclear fuel resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. The Company estimates that the reduced output and upcoming outages at Palo Verde Unit 1, together with lower than originally forecast wholesale energy prices, will result in reduced off-system sales margins of approximately $12 to $18 million for the period January through July 2006. The Company cautions that results would differ from its estimates to the extent that actual market prices, Palo Verde Unit 1 operations and other factors vary from its assumptions. The adverse financial impact on the Company from continued reduced output and outages at Palo Verde Unit 1 could increase and would include foregone off-system margins, higher capital and/or operating costs and increased purchased power and other costs.

Index to Financial Statements

Our City Rate Agreement with El Paso Could Terminate Early

Under our City Rate Agreement, we agreed to engage the services of an independent consultant to review the reasonableness of certain operating expenses. If the consultant finds such expenses to be unreasonable, the parties will seek to negotiate an appropriate remedy. If the parties are unable to agree on a remedy, the New Texas Freeze Period would expire on June 30, 2006. If that were to occur, we would be subject to traditional rate regulation by the City with appellate review by the Texas Commission beginning July 1, 2006. In such event, there can be no assurance that we would be able to maintain our Texas rates thereafter. In addition, the early termination of the New Texas Freeze Period or denial by the Texas Commission to approve the fuel provision of the City Rate Agreement may mean that we would not be entitled to retain 75% of our margins from off-system sales retroactive to July 1, 2005. If litigated rate regulation leads to lower rates or reduced off-system sales margin retention, there would be a potential material negative impact on our revenues, earnings, cash flows and financial position.

We May Not Be Able to Pass Through All of Our Fuel Expenses to Customers

In general, by law, we are entitled to pass through our prudently incurred fuel and purchased power expenses to our customers in Texas and New Mexico. Nevertheless, we agreed in 2004 to a fixed fuel factor for ten percent of the kilowatt-hours of our retail customers in New Mexico pursuant to a base rate freeze that expires in 2007. This agreement also allows us to price a portion of power from Palo Verde Unit 3 at market prices which tend to track gas prices. To the extent that this indirect “hedge” does not perfectly track our costs, we are subject to the risk of increased costs of fuel that would not be recoverable. The portion of fuel expense that is not fixed is subject to reconciliation by the Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel transactions such that fuel revenues equal fuel expense except for the portion fixed in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers and we would incur a loss to the extent of the disallowance.

In New Mexico, the fuel adjustment clause allows us to reflect current fuel cost in the fuel clause and to recover under-recoveries and refund over-recoveries with a two month lag. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted two times per year. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at the time of the next fuel factor filing. During periods of significant increases in natural gas prices such as occurred in 2004 and 2005, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms. As a result, the cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. At December 31, 2005 and December 31, 2004, the Company had deferred fuel balances of $92 million and $19 million, respectively. A surcharge to collect fuel under-recoveries of $53 million over a 24 month period was placed into effect in Texas in October 2005. A second surcharge was placed into effect on an interim basis in Texas in February 2006 to collect $34 million over a twelve month period. To the extent the fuel recovery processes in Texas and New Mexico do not provide for the timely recovery of fuel costs, the Company could experience a material negative impact on its cash flow.

To insure that we have adequate liquidity we have recently begun the process of replacing our $100 million revolving credit facility with a new $150 million revolving credit facility. The new revolving credit facility will have similar terms to the existing revolving credit facility and will provide up to $70 million for nuclear fuel purchases with any amounts not borrowed for nuclear fuel purchases

Index to Financial Statements

available for use for working capital. The Company expects, but has no assurance, that the new revolving credit facility will be in place by the second quarter of 2006.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are particularly vulnerable to this due to the advanced age of several of our gas-fired generating units in or near El Paso. In addition, we are seeking to extend the lives of these plants. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. These factors, as well as weather, interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.

Competition and Deregulation Could Result in a Loss of Customers and Increased Costs

As a result of changes in federal law, our wholesale and large retail customers already have, in varying degrees, alternate sources of economical power, including co-generation of electric power. Texas has recently passed industry deregulation legislation requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. On October 13, 2004, the Texas Commission approved a rule delaying retail competition in our Texas service territory. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flows and financial condition.

Item 1B.

Unresolved Staff Comments

We do not have unresolved SEC staff comments to disclose.

Index to Financial Statements

Executive Officers of the Registrant

The executive officers of the Company as of February 2, 2006, were as follows:


Name	Age	Current Position and Business Experience
Gary R. Hedrick	51	Chief Executive Officer, President and Director since November 2001; Executive Vice President, Chief Financial and Administrative Officer from August 2000 to November 2001.

J. Frank Bates	55	Executive Vice President and Chief Operating Officer since May 2005; Executive Vice President and Chief Operations Officer from November 2001 to May 2005; Vice President – Transmission and Distribution from August 1996 to November 2001.

Scott D. Wilson	52	Executive Vice President, Chief Financial and Chief Administrative Officer since February 2006; Senior Vice President, Chief Financial Officer from May 2005 to February 2006; Vice President – Corporate Planning and Controller from February 2005 to May 2005; Controller from September 2003 to February 2005; Owner of Wilson Consulting Group from June 1992 to September 2003.

Steven P. Busser	37	Vice President – Regulatory Affairs and Treasurer since February 2005; Treasurer from February 2003 to February 2005; 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.

David G. Carpenter	50	Vice President – Corporate Planning and Controller since August 2005; Director – Texas Regulatory Services for American Electric Power Services Corporation from June 2000 to August 2005 with responsibility for all regulatory activities in Texas for the three American Electric Power Co., Inc. electric utility subsidiaries in Texas.

Fernando J. Gireud	48	Vice President – Safety, Environmental, Power Marketing and International Affairs since February 2006; Vice President – Power Marketing and International Business from February 2003 to February 2006; 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.

Helen Knopp	63	Vice President – Customer and Public Affairs since April 1999.

Kerry B. Lore	46	Vice President – Administration since May 2003; Controller from October 2000 to May 2003.

Robert C. McNiel	59	Vice President – New Mexico Affairs since December 1997.

Hector R. Puente	49	Vice President – Distribution since February 2006; Vice President – Power Generation from April 2001 to February 2006; Manager – Substations and Relaying from August 1996 to April 2001.

Andres Ramirez	45	Vice President – Power Generation since February 2006; Vice President – Safety, Environmental and Resource Planning from July 2005 to February 2006; Executive Director – Operations for Sempra Energy Texas Service from August 2004 to July 2005; Senior Vice President – Power Production for Austin Energy from 2001 to 2004.

Gary Sanders	47	General Counsel since February 2006; Assistant General Counsel and Assistant Secretary from July 2004 to February 2006; Assistant General Counsel from January 2003 to July 2004; Shareholder in law firm of Gordon & Mott PC from April 1994 to December 2002.

Guillermo Silva, Jr.	52	Corporate Secretary since February 2006; Vice President – Information Services from February 2003 to February 2006; Corporate Secretary from January 1994 to February 2003.

John A. Whitacre	56	Vice President – Transmission since February 2006; Vice President – Transmission and Distribution from July 2002 to February 2006; Assistant Vice President – System Operations from August 1989 to July 2002.

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

Index to Financial Statements

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 $100 million of Collateral Series H First Mortgage Bonds.

In addition, the Company leases executive and administrative offices in El Paso, Texas under a lease which expires in May 2007 and certain warehouse facilities in El Paso, Texas under a lease which expires in January 2007 with two concurrent renewal options of six months each.

Item 3.

Legal Proceedings

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, to the extent that the Company has been able to reach a conclusion as to its ultimate liability, it believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

On 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. 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. On April 13, 2004, the Court granted a motion of the Company and the remaining individual defendants requesting permission to file an interlocutory appeal to the U. S. Court of Appeals for the Fifth Circuit regarding certain legal questions relating to the Court’s denial of the motion to dismiss the complaint as to those defendants. On April 27, 2004, the Court entered an order staying the district court proceedings until the Fifth Circuit completed its review. On June 7, 2004, the U. S. Court of Appeals denied the appeal which automatically lifted the stay in the district court. While the Company believed the lawsuit was without merit, the parties reached a settlement to resolve this case. The parties filed a Stipulation of Settlement with the Court on June 2, 2005, and the Court issued a final order approving the settlement on September 15, 2005. The settlement was paid by the Company’s insurance carrier since the deductible had been met and did not require any further charge to the Company’s earnings.

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

Index to Financial Statements

antitrust laws, as well as for 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. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle has filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. The parties are awaiting a hearing and decision on that appeal. While the Company believes that these matters are without merit, the Company is unable to predict the outcome or range of any possible loss.

On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint makes substantially the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases. Wah Chang and the City of Tacoma have both filed notices of appeal with the U.S. Court of Appeals for the Ninth Circuit. The parties have filed briefs in both cases and are awaiting a hearing and decision. While the Company believes that these matters are without merit and intends to defend itself vigorously, the Company is unable to predict the outcome or range of possible loss.

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

Item 4.

Submission of Matters to a Vote of Security Holders

No matter was submitted to vote of the Company’s security holders through the solicitation of proxies or otherwise during the fourth quarter of 2005.

Index to Financial Statements

PART II

Item 5.

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

The Company’s common stock trades on the New York Stock Exchange under the symbol “EE.” The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the New York Stock Exchange for the periods indicated below were as follows:


	Sales Price
	High		Low		Close
					(End of period)
2004
First Quarter	$	14.68	$	13.07	$	13.84
Second Quarter		15.60		13.42		15.44
Third Quarter		16.10		14.58		16.07
Fourth Quarter		19.12		15.90		18.94
2005
First Quarter	$	20.85	$	17.80	$	19.00
Second Quarter		21.44		18.52		20.45
Third Quarter		22.10		19.76		20.85
Fourth Quarter		22.42		20.07		21.04

As of January 31, 2006, there were 4,293 holders of record of the Company’s common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its stock repurchase programs with the goal of maintaining or improving its capital structure, bond ratings, and earnings per share.

Since the inception of the stock repurchase programs in 1999, the Company has repurchased a total of approximately 15.3 million shares of its common stock at an aggregate cost of $175.6 million, including commissions. Approximately 1.7 million shares remain authorized to be repurchased under the currently authorized program. No shares were repurchased during 2005. The Company may continue making purchases of its stock pursuant to its stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

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

Index to Financial Statements

Item 6.

Selected Financial Data

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


	Years Ended December 31,
	2005			2004		2003		2002		2001
Operating revenues	$	803,913		$	708,628	$	664,362	$	690,085	$	769,705
Operating income	$	107,883		$	93,071	$	79,370	$	110,127	$	167,122
Income before cumulative effect of accounting change and extraordinary item	$	36,615		$	33,369	$	20,322	$	28,674	$	63,365
Cumulative effect of accounting change, net of tax	$	(1,093	)	$	—	$	39,635	$	—	$	—
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—		$	1,802	$	—	$	—	$	—
Net income	$	35,522		$	35,171	$	59,957	$	28,674	$	63,365
Basic earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	0.77		$	0.70	$	0.42	$	0.58	$	1.25
Cumulative effect of accounting change, net of tax	$	(0.02	)	$	—	$	0.82	$	—	$	—
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—		$	0.04	$	—	$	—	$	—
Net income	$	0.75		$	0.74	$	1.24	$	0.58	$	1.25
Weighted average number of shares outstanding		47,711,894			47,426,813		48,424,212		49,862,417		50,821,140
Diluted earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	0.76		$	0.69	$	0.42	$	0.57	$	1.23
Cumulative effect of accounting change, net of tax	$	(0.02	)	$	—	$	0.81	$	—	$	—
Extraordinary gain on re-application of SFAS No. 71, net of tax	$	—		$	0.04	$	—	$	—	$	—
Net income	$	0.74		$	0.73	$	1.23	$	0.57	$	1.23
Weighted average number of shares and dilutive potential shares outstanding		48,307,910			48,019,721		48,814,761		50,380,468		51,722,351
Cash additions to utility property, plant and equipment	$	88,263		$	72,092	$	77,679	$	65,065	$	70,739
Total assets	$	1,665,449		$	1,580,835	$	1,596,614	$	1,648,229	$	1,646,158
Long-term debt and financing and capital lease obligations, net of current portion	$	611,018		$	379,636	$	608,722	$	614,375	$	619,365
Common stock equity	$	556,439		$	532,147	$	495,768	$	452,882	$	446,726

Certain amounts presented for prior years have been reclassified to conform with the 2005 presentation.

Index to Financial Statements

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Summary of Critical Accounting Policies and Estimates

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

•

SFAS No. 71

•

Collection of fuel expense

•

Value of net utility plant in service

•

Decommissioning costs and estimated asset retirement obligation

•

Future pension and other postretirement obligations

•

Reserves for tax dispute

SFAS No. 71

Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71. Under this accounting standard, certain recoverable costs are shown as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utility’s cost of service.

Beginning in 1991, we discontinued the application of SFAS No. 71 to our financial statements. This decision was based on our determination that our rates were no longer designed to recover our costs of providing service to customers. Upon emerging from bankruptcy in 1996, we again concluded that we did not meet the criteria for applying SFAS No. 71 because of the ten-year rate freeze in Texas and our ongoing intention not to seek changes in our New Mexico rates, which had been established in 1990. Although we believe the rates established in 1995 were based upon our costs of service, the unusual length of the rate freeze period created substantial uncertainty as to the ultimate recovery of our costs over the entire freeze period. Consequently, we determined that we should not re-apply SFAS No. 71 to our Texas and New Mexico jurisdictions at the time we emerged from bankruptcy in February 1996.

During 2004, we determined that we met the criteria necessary to re-apply SFAS No. 71 to our New Mexico jurisdictional operations. Two key events transpired in New Mexico that, when considered together, resulted in our decision to re-apply SFAS No. 71. In April of 2004, we received a final order approving a unanimous stipulation which established new base and fuel rates for our New Mexico customers which were implemented June 1, 2004. Our approved rates were based upon our cost of providing service in New Mexico. That event, coupled with the repeal of New Mexico’s electric utility

Index to Financial Statements

industry restructuring law which occurred in April of 2003, resulted in us meeting the criteria for the re-application of SFAS No. 71 to New Mexico, beginning July 1, 2004. The re-application of SFAS No. 71 to our New Mexico jurisdiction resulted in the recording of $18.5 million of regulatory assets, $5.0 million in related accumulated deferred income tax assets, $16.2 million of regulatory liabilities, $5.5 million in related accumulated deferred tax liabilities and a $1.8 million extraordinary gain, net of tax, or $0.04 basic and diluted earnings per share.

We have not reapplied SFAS No. 71 to our Texas jurisdiction. However, we are currently evaluating the re-application of SFAS No. 71 to our Texas jurisdiction based upon the expiration of the ten year rate freeze in Texas, the delay of retail competition in 2004, and a new rate settlement agreement with the City of El Paso. In July 2005, we entered into a settlement agreement with the City (“City Rate Agreement”) which provides for a new rate freeze (“New Texas Freeze Period”) until June 30, 2010. The City Rate Agreement specifically provides for our rates to be cost based. If our return on equity falls below a range around a calculated return on equity under current market conditions during the New Texas Freeze Period, we may seek to increase rates. Likewise, if our return on equity exceeds the range, 50% of the excess must be paid to the City. The City Rate Agreement provides for the City to conduct a review of our operating expenses and provides for revision of the rate agreement if they are not determined to be within a reasonable range compared to the utility industry. Also, the City Rate Agreement allows us to retain 75% of off-system sales margins rather than the previous 50%. While the City Rate Agreement has been approved by the City, in order to fully implement the agreement, the Texas Commission must approve the sharing of off-system sales margin provisions of the agreement and, in effect, the entire agreement for the Texas customers outside the City. Once the City Rate Agreement is approved by the Texas Commission, we will complete the evaluation as to whether SFAS No. 71 should be re-applied to our Texas jurisdiction. The re-application of SFAS No. 71 will result in the recognition of regulatory assets and liabilities that could have a material effect on our consolidated financial statements. However, the re-application of SFAS No. 71 will have no effect on our cash flow.

Collection of Fuel Expense

In general, through regulation, our fuel and purchased power expenses are passed through to our customers. As discussed later, in times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel transactions such that fuel revenues equal fuel expense except for the fixed portion in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

Value of Net Utility Plant in Service

In 1996, when we emerged from bankruptcy, we recast our 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, we attributed value to our integrated utility system after we had established the value of our pro forma capital structure based on management’s estimates of future operating results. We valued our assets such that the depreciated value of our assets would be approximately equal to their estimated fair value at the end of the Freeze Period.

Index to Financial Statements

The depreciation of the fresh-start asset value was completed in July 2005. If at any time we determine that estimated, undiscounted future net cash flows from the operations of our assets are not sufficient to recover their net book value, then we will be required to write down the value of these assets to their fair values. Any such writedown would be charged to earnings. We currently believe that our rates are sufficient and that future net cash flows from our assets will be sufficient to recover their net book values.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2 and 3 and associated common areas. We recorded a liability and a corresponding asset for the fair value of our decommissioning obligation upon implementation of SFAS No. 143, “Accounting for Asset Retirement Obligations.” We will adjust the liability to its present value periodically over time, and the corresponding asset will be depreciated over its useful life. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates.

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

Future Pension and Other Postretirement Obligations

Our obligations to retirees under various benefit plans are recorded as a liability on the consolidated balance sheets. Our liability is calculated on the basis of significant assumptions regarding discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. Our assumptions as well as a sensitivity analysis of the effect of hypothetical changes in certain assumptions are set forth in detail in Note K, “Employee Benefits”, to the Notes to Consolidated

Index to Financial Statements

Financial Statements. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the consolidated balance sheets.

In developing the assumptions, management makes judgments based on the advice of financial and actuarial advisors and our review of third-party and market-based data. These sources include life expectancy tables, surveys of compensation and health care cost trends, and historical and expected return data on various categories of plan assets. The assumed discount rate applied to future plan obligations is based at each measuring date on prevailing market interest rates inherent in high quality (AA and better) corporate bonds that would provide future cash flow needed to pay the benefits as they become due, as well as on publicly available bond issues. We regularly review our assumptions and conduct a reassessment at least once a year. We do not expect that any such change in assumptions will have a material effect on net income for 2006.

Reserves for Tax Dispute

Our federal income tax returns for the years 1999 through 2002 have been examined by the Internal Revenue Service (“IRS”). On May 9, 2005, we received a notice of proposed deficiency from the IRS. The primary audit adjustments proposed by the IRS related to (i) whether we were entitled to currently deduct payments related to the repair of the Palo Verde Unit 2 steam generators or whether these payments should be capitalized and depreciated and (ii) whether we were entitled to currently deduct payments related to the dry cask storage facilities for spent nuclear fuel or whether these payments should be capitalized and depreciated. The proposed IRS adjustments go to the timing of these deductions not their ultimate deductibility for federal tax purposes. We have protested the audit adjustments through administrative appeals and believe that our treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to our cash flows. The IRS is currently performing an examination of the 2003 and 2004 income tax returns. We have established, and periodically review and re-evaluate, an estimated contingent tax liability on our consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome of the appeals case or the ongoing examination cannot be predicted with certainty, we believe that, as of December 31, 2005, adequate provision has been made for any additional tax that may be due.

Overview

The following is an overview of our results of operations for the years ended December 31, 2005, 2004 and 2003. Income for the years ended December 31, 2005, 2004 and 2003 is shown below:


	Years Ended December 31,
	2005		2004		2003
Net income before cumulative effect of accounting change and extraordinary item (in thousands)	$	36,615	$	33,369	$	20,322
Basic earnings per share before cumulative effect of accounting change and extraordinary item		0.77		0.70		0.42

Index to Financial Statements

The following table and accompanying explanation show the primary factors affecting the after-tax change in income before cumulative effect of accounting changes and extraordinary item between the calendar years ended 2005 and 2004, 2004 and 2003, and 2003 and 2002 (in thousands):


	2005			2004			2003
Prior year December 31 income before cumulative effect of accounting change and extraordinary item	$	33,369		$	20,322		$	28,674
Change in (net of tax):
Decreased (increased) depreciation and amortization expense		6,760	(a)		(3,566	)		1,489
Increased retail base revenues		5,905	(b)		1,897			5,630
Decreased interest charges on long-term debt		5,212	(c)		1,384			2,294
Coal reclamation liability adjustment (d)		1,902			(1,498	)		—
Increased (decreased) off-system sales margins		456			(522	)		6,289
Decreased (increased) maintenance at coal and gas-fired generating plants		147			3,348			(1,038	)
Impairment loss (e)		—			10,897			(10,897	)
Texas fuel disallowances (f)		—			2,788			(2,788	)
FERC settlements (g)		—			—			9,455
Decreased sales for resale		—			(960	)		(17,028	)(h)
Decreased (increased) loss on extinguishments of debt		(8,807	)(i)		(3,320	)		2,079
2004 IRS settlement (j)		(6,200	)		6,200			—
Increased Palo Verde operations and maintenance expense		(2,189	)(k)		(2,585	)		(1,311	)
Decreased (increased) taxes other than income taxes		(1,514	)(l)		90			300
Increased ARO accretion		(259	)		(282	)		(2,919	)(m)
Other		1,833			(824	)		93

Current year December 31 net income before cumulative effect of accounting change and extraordinary item	$	36,615		$	33,369		$	20,322

(a)	Depreciation and amortization decreased due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended in July 2005.

(b)	Retail base revenues increased in 2005 compared to 2004 primarily due to (i) increased kWh sales to our residential customers reflecting growth in the number of customers served and (ii) favorable summer weather conditions.

(c)	Interest charges decreased due to lower interest expense on long-term debt and financing obligations resulting from the refinancing of first mortgage bonds with long-term senior notes and the August 2005 reissuance and remarketing of pollution control bonds at lower interest rates.

(d)

The coal reclamation liability adjustment pertains to the updated 2004 reclamation study for the coal mine which supplies the Four Corners power plant. We had previously recorded this liability based on a 1998 study and adjusted the liability in December 2004. An additional true-up was recorded in September 2005.

(e)	We abandoned the development of a customer information system project and recognized an asset impairment loss in the third quarter of 2003.

(f)	Texas fuel disallowance in Docket No. 26194 was recorded in 2003.

(g)	The FERC settlements relate to the settlements with FERC Trial Staff and principal California parties in which we agreed to refund revenues we earned on wholesale power transactions in 2000 and 2001. These settlements were recorded in December 2002.

(h)	The 2003 decrease in wholesale sales revenue relates primarily to the expiration of two long-term contracts.

(i)	Loss on extinguishments of debt in 2005 increased compared to 2004, reflecting the refinancing of all of our first mortgage bonds in June 2005.

(j)	A benefit was recorded in the third quarter of 2004 from a settlement of an IRS audit of our 1996-1998 tax returns with no comparable amount in 2005.

(k)	Palo Verde operations and maintenance expense increased in 2005 when compared to 2004 due to increased operations and maintenance expense at Unit 1 during the planned replacement of steam generators and refueling outage in late 2005, and increased administrative and general expenses.

(l)	Taxes other than income taxes increased in 2005 compared to 2004 due to an increase in the El Paso city franchise fee rate which took effect on August 2, 2005, partially offset by a decrease in property taxes.

(m)	Accretion expense pursuant to SFAS No. 143 was first recognized in 2003.

Index to Financial Statements

Historical Results of Operations

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

Operating revenues

We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market based prices. Sales for resale (which are wholesale sales within our service territory) accounted for less than 1% of revenues. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Under the terms of our City Rate Agreement, we share with our Texas customers 25% of our off-system sales margins and wheeling revenues.

Revenues from the sale of electricity include fuel costs, which are substantially passed through to customers through fuel adjustment mechanisms in Texas and New Mexico and a portion through base revenues in New Mexico. We record deferred fuel revenues for the difference between fuel costs and fuel revenues until such amounts are collected from or refunded to customers. “Base revenues” refers to our revenues from the sale of electricity excluding such fuel costs except for a portion of fuel costs in New Mexico.

Retail base revenues. Retail base revenues increased by $9.5 million or 2.1% for the twelve months ended December 31, 2005 when compared to the same period in 2004. Retail kilowatt-hour sales in the twelve month period ended December 31, 2005 were 1.1% higher than the twelve month period ended December 31, 2004. A 2.7% growth in the average number of retail customers served in 2005 accounted for most of the growth in sales. While hotter weather in the summer of 2005 (increased cooling degree days) resulted in higher sales, they were offset by milder weather conditions earlier in 2005 (decreased heating degree days).

Retail base revenues increased by $3.1 million for the twelve months ended December 31, 2004 when compared to the same period in 2003. Retail kilowatt-hour sales in the twelve month period ended December 31, 2004 were 2.0% higher than the twelve month period ended December 31, 2003. A 2.7% growth in the average number of retail customers served in 2004 accounted for most of the growth in sales. Cooler weather in the summer of 2004 (decreased cooling degree days) resulted in lower sales and were only partially offset by the colder winter months (increased heating degree days).

Index to Financial Statements

Retail base revenue percentages by customer class are presented below:


	Twelve Months Ended December 31,
	2005		2004		2003
Residential	39	%	38	%	38	%
Commercial and industrial, small	36		36		36
Commercial and industrial, large	9		10		10
Sales to public authorities	16		16		16

Total base revenues	100	%	100	%	100	%

No retail customer accounted for more than 2% of our base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 75% of our revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. As a result, our business is seasonal, with higher revenues during the summer cooling season. The following table sets forth the percentage of our revenues derived during each quarter for the periods presented:


	Years Ended December 31,
	2005		2004		2003
January 1 to March 31	20	%	22	%	22	%
April 1 to June 30	23		26		24
July 1 to September 30	30		29		30
October 1 to December 31	27		23		24

Total	100	%	100	%	100	%

Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. As shown in the table below, combined heating and cooling degree days were below average in 2004 and 2005.


	2005	2004	2003	10-year Average
Heating degree days	2,176	2,558	2,233	2,405
Cooling degree days	2,549	2,327	2,695	2,530

Fuel revenues. Fuel revenues consists of two parts, revenues collected from customers under fuel recovery mechanisms approved by the state commissions, and deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers. In New Mexico, the fuel adjustment clause allows us to reflect current fuel costs in the clause and to recover under or refund over-recoveries in the clause with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted two times per year. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Natural gas prices increased significantly in 2005 and 2004 resulting in a significant increase in deferred fuel revenues particularly in Texas due to the lag in reflecting current fuel prices in the fuel recovery mechanism. The increase in

Index to Financial Statements

deferred fuel revenues for the twelve months ended December 31, 2005 when compared to 2004 was $62.2 million. The increase in deferred fuel revenues for the twelve months ended December 31, 2004 when compared to 2003 was $30.6 million.

In July 2005 we filed for an increase in our fixed fuel factor and to surcharge fuel under-recoveries with the Texas Commission. A settlement approved by the Texas Commission has allowed us to increase our fixed fuel factor and to surcharge $53.6 million of fuel under-recoveries, including interest as of the end of the under-recovery period, over a 24-month period. In January 2006, we again filed with the Texas Commission to increase our fixed fuel factor and surcharge approximately $34 million for additional fuel under-recoveries, including interest for the period of September through November 2005, over a twelve-month period. We received Commission approval to implement the new fuel factor and surcharge on an interim basis beginning with February 2006 billings.

Fuel revenues recovered from customers increased $20.8 million for the twelve months ended December 31, 2005 compared to 2004 and $7.7 million for the twelve months ended December 31, 2004 compared to 2003. These increases are primarily due to the increased fuel costs that are collected from our New Mexico customers on a two-month lag and the increase in Texas fuel factors in October 2005 along with an increase in kWh sales for the related period. Fuel revenues also increased for the twelve months ended December 31, 2004 compared to 2003 due to the Texas fuel disallowance in Docket No. 26194 of $4.5 million that was recorded in 2003 with no comparable amount in 2004.

Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Off-system sales decreased $0.3 million for the twelve months ended December 31, 2005 when compared to 2004 due to a decline in energy available to sell in the off-system market because of a decline in output at the Palo Verde station due to an extended planned refueling and steam generator replacement for Unit 1 and unplanned outages at Palo Verde Units 2 and 3. Offsetting this decrease in available power were higher average market prices. Off-system sales increased $2.0 million for the twelve months ended December 31, 2004 when compared to 2003 primarily due to higher average market prices.

Index to Financial Statements

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


					Increase (Decrease)
Years Ended December 31:	2005		2004		Amount			Percent
kWh sales:
Retail:
Residential		2,090,098		1,986,085		104,013		5.2	%
Commercial and industrial, small		2,126,918		2,115,822		11,096		0.5
Commercial and industrial, large		1,165,506		1,236,426		(70,920	)	(5.7	)
Sales to public authorities		1,270,116		1,243,003		27,113		2.2

Total retail sales		6,652,638		6,581,336		71,302		1.1

Wholesale:
Sales for resale		41,883		41,094		789		1.9
Off-system sales		1,420,778		1,838,467		(417,689	)	(22.7	)(2)

Total wholesale sales		1,462,661		1,879,561		(416,900	)	(22.2	)

Total kWh sales		8,115,299		8,460,897		(345,598	)	(4.1	)

Operating revenues:
Base revenues:
Retail:
Residential	$	183,667	$	174,752	$	8,915		5.1	%
Commercial and industrial, small		167,241		165,760		1,481		0.9
Commercial and industrial, large		41,321		43,150		(1,829	)	(4.2	)
Sales to public authorities		73,677		72,720		957		1.3

Total retail base revenues (1)		465,906		456,382		9,524		2.1

Wholesale:
Sales for resale		1,687		1,675		12		0.7

Total base revenues		467,593		458,057		9,536		2.1

Fuel revenues:
Recovered from customers during the period		164,500		143,692		20,808		14.5
Change in deferred fuel revenues		79,539		17,360		62,179		358.2	(3)

Total fuel revenues		244,039		161,052		82,987		51.5
Off-system sales		78,209		78,533		(324	)	(0.4	)
Other		14,072		10,986		3,086		28.1	(4)(5)

Total operating revenues	$	803,913	$	708,628	$	95,285		13.4

(1)	Includes fuel recovered through New Mexico base rates of $29.4 million and $28.0 million for 2005 and 2004, respectively.

(2)	Primarily due to reduced output from Palo Verde.

(3)	Primarily due to an increase in recoverable fuel expenses as a result of an increase in the price and volume of natural gas burned and an increase in purchased power costs.

(4)	Represents revenues with no related kWh sales.

(5)	Primarily due to increased transmission revenues.

Index to Financial Statements


						Increase (Decrease)
Years Ended December 31:	2004		2003			Amount			Percent
kWh sales:
Retail:
Residential		1,986,085		1,932,171			53,914		2.8	%
Commercial and industrial, small		2,115,822		2,096,860			18,962		0.9
Commercial and industrial, large		1,236,426		1,197,065			39,361		3.3
Sales to public authorities		1,243,003		1,224,349			18,654		1.5

Total retail sales		6,581,336		6,450,445			130,891		2.0

Wholesale:
Sales for resale		41,094		67,754			(26,660	)	(39.3	)(2)
Off-system sales		1,838,467		1,920,882			(82,415	)	(4.3	)

Total wholesale sales		1,879,561		1,988,636			(109,075	)	(5.5	)

Total kWh sales		8,460,897		8,439,081			21,816		0.3

Operating revenues:
Base revenues:
Retail:
Residential	$	174,752	$	171,459		$	3,293		1.9	%
Commercial and industrial, small		165,760		165,434			326		0.2
Commercial and industrial, large		43,150		43,294			(144	)	(0.3	)
Sales to public authorities		72,720		73,136			(416	)	(0.6	)

Total retail base revenues (1)		456,382		453,323			3,059		0.7

Wholesale:
Sales for resale		1,675		3,223			(1,548	)	(48.0	)(2)

Total base revenues		458,057		456,546			1,511		0.3

Fuel revenues:
Recovered from customers during the period		143,692		135,956			7,736		5.7
Change in deferred fuel revenues		17,360		(13,195	)		30,555		231.6	(3)

Total fuel revenues		161,052		122,761			38,291		31.2

Off-system sales		78,533		76,536			1,997		2.6
Other		10,986		8,519			2,467		29.0	(4)(5)

Total operating revenues	$	708,628	$	664,362		$	44,266		6.7

(1)	Includes fuel recovered through New Mexico base rates of $28.0 million and $27.4 million for 2004 and 2003, respectively.

(2)	Primarily due to 2003 CFE wholesale power sales with no comparable sales in 2004.

(3)	Primarily due to increase in recoverable fuel expenses as a result of an increase in the price and volume of natural gas burned and an increase in purchased power costs.

(4)	Represents revenues with no related kWh sales.

(5)	Primarily due to increased transmission revenues.

Index to Financial Statements

Energy expenses

Our energy sources are derived from nuclear fuel, natural gas, coal, and purchased power. Palo Verde represents approximately 40% of our available net generating capacity and approximately 46% of our available energy for the twelve months ended December 31, 2005.

Our energy expenses increased $82.0 million for the twelve months ended December 31, 2005 when compared to 2004 primarily due to (i) increased natural gas costs of $72.2 million due to increased prices and volume burned and (ii) increased costs of purchased power of $13.6 million due to higher market prices. These increases were partially offset in 2005 by a $0.7 million decrease to our coal reclamation liability record in 2005 compared to a $2.2 million increase in our coal reclamation costs recorded in 2004. Energy expenses increased $39.9 million for the twelve months ended December 31, 2004 compared to 2003 primarily due to (i) increased natural gas costs of $27.2 million due to increased prices and volume burned; (ii) increased costs for purchased power of $10.9 million due to increased volume and higher average market prices; and (iii) a $2.2 million increase in our coal reclamation liability in 2004 with no comparable amount in 2003.


	2005						2004
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	230,900		2,643,584	$	87.34	$	158,725	(a)	2,426,567	$	65.41
Coal		11,003	(b)	779,002		14.12		10,027	(b)	740,960		13.53
Nuclear		21,619		4,077,558		5.30		22,790		4,443,928		5.13

Total		263,522		7,500,144		35.14		191,542		7,611,455		25.16
Purchased power		80,040		1,258,469		63.60		66,451		1,410,114		47.12

Total energy	$	343,562		8,758,613		39.23	$	257,993		9,021,569		28.60

(a)	Excludes a $0.7 million contract termination fee.

(b)	Excludes a reduction of $0.7 million and an increase of $2.2 million to our coal reclamation liability recorded in 2005 and 2004, respectively.

Other operations expense

Other operations expense increased $4.8 million in 2005 compared to 2004 primarily due to (i) increased Palo Verde expense of $3.1 million; (ii) increased other postretirement benefit costs of $2.0 million; and (iii) increased wheeling costs of $1.9 million. These increases were partially offset by decreased regulatory expense of $1.1 million related to FERC matters and the receipt of a sales tax refund of $0.9 million in 2005 with no comparable activity in 2004.

Other operations expense increased $5.7 million in 2004 compared to 2003 primarily due to increased pension and benefits expense of $6.1 million (including a $3.2 million increase in employee bonuses), and increased Palo Verde operations expense of $1.7 million. These increases were partially offset by decreased insurance-related expenses of $1.5 million and decreased customer accounts expense of $1.5 million.

Maintenance expense

Maintenance expense increased $2.1 million in 2005 compared to 2004 primarily due to increased environmental expenses of $1.2 million related to remediation projects and increased maintenance at Palo Verde of $0.4 million.

Index to Financial Statements

Maintenance expense decreased $3.1 million in 2004 compared to 2003 primarily due to a decrease in maintenance expense at our gas-fired generating plants of $5.4 million offset by increased maintenance at Palo Verde of $2.4 million due to the timing of scheduled refueling and maintenance outages.

Impairment loss on CIS project

We abandoned a customer information system (CIS) project and recognized an asset impairment loss of $17.6 million in September 2003.

Depreciation and amortization expense

Depreciation and amortization expense decreased $10.9 million in 2005 compared to 2004 primarily due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended in July 2005. The decrease was partially offset by higher depreciation due to increases in depreciable plant balances. Depreciation and amortization expense increased $5.8 million in 2004 compared to 2003 primarily due to depreciation on new Palo Verde Unit 2 steam generators of $2.2 million, the implementation of new depreciation rates based on a new depreciation study resulting in an increase of $1.9 million and increased other depreciable plant balances resulting in an increase of $1.7 million.

Taxes other than income taxes

Taxes other than income taxes increased by $2.4 million, or 5.7%, in 2005 compared to 2004 primarily due to an increase in the El Paso city franchise fees which took effect August 2, 2005, which was partially offset by a decrease in New Mexico occupation street rental tax. As a result of a June 2004 change in New Mexico law, the occupation street rental tax on retail sales of electricity is now collected directly from retail customers and not recorded as an expense. Taxes other than income taxes were relatively unchanged in 2004 compared to 2003.

Other income (deductions)

Other income (deductions) decreased $12.8 million in 2005 compared to 2004 primarily due to an increase in the loss on extinguishment of debt of $14.2 million, as a result of the refinancing of our first mortgage bonds in the second quarter of 2005. This decrease was partially offset by increased interest income in 2005 of $2.2 million primarily related to a $1.1 million adjustment to reduce interest income associated with the resolution of the Texas fuel reconciliation in PUC Docket No. 26194 recorded in 2004 with no comparable activity in 2005, and the receipt of $0.6 million interest related to a sales tax refund in 2005.

Other income (deductions) decreased $4.9 million in 2004 compared to 2003 primarily due to (i) losses on extinguishment of debt of $5.4 million recorded in 2004 with no comparable activity in 2003; (ii) a $1.1 million reduction in interest income in 2004 associated with the resolution of the Texas fuel reconciliation in PUC Docket No. 26194; and (iii) $1.0 million related to certain tax refunds received in 2003 with no comparable amount in 2004. These decreases were partially offset by an increase of $2.4 million in investment and interest income related to the decommissioning trust fund.

Index to Financial Statements

Interest charges (credits)

Interest charges (credits) decreased $10.6 million in 2005 compared to 2004 due to an $8.4 million decrease in interest on long-term debt and financing obligations resulting from (i) the repurchase and retirement of our first mortgage bonds; (ii) the May 2005 issuance of unsecured senior notes at a lower interest rate than the first mortgage bonds; and (iii) the reissuance or remarketing of our pollution control bonds in August 2005 at lower interest rates. The decrease was also due to increased capitalized interest of $2.4 million due to an increase in construction work in progress related to Palo Verde Unit 1 and Unit 3 steam generators. Interest charges (credits) decreased slightly in 2004 compared to 2003 primarily due to decreased interest expense of $2.2 million due to a reduction of outstanding debt as a result of open market purchases of our first mortgage bonds, partially offset by a reduction in capitalized interest of $2.1 million as a result of transferring new Palo Verde Unit 2 steam generators to plant in service.

Income tax expense

Income tax expense, before the cumulative effect of an accounting change and an extraordinary item, increased $9.4 million in 2005 compared to 2004 and decreased $4.0 million in 2004 compared to 2003 primarily due to the $6.2 million benefit from the IRS settlement recorded in the third quarter of 2004 and for changes in pretax income and certain permanent differences.

Cumulative effect of accounting change

The cumulative effect of accounting change for 2005 of $1.1 million, net of tax, relates to the adoption of FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”) in December 2005. FIN 47 provides guidance on the recognition and measurement of liabilities associated with the retirement and disposal obligations of tangible long-lived assets not already accounted for under SFAS No. 143. FIN 47 affected the accounting for the disposal obligations of our fuel oil storage tanks, water wells, evaporative ponds and asbestos at our gas-fired generating stations. The cumulative effect of accounting change for 2003 relates to the adoption of SFAS No. 143 on January 1, 2003, which also 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 our portion of the Palo Verde and Four Corners Stations and changed the method used to report the decommissioning obligation.

Extraordinary gain

The extraordinary gain on re-application of SFAS No. 71 relates to our third quarter 2004 determination that we met the criteria necessary to re-apply SFAS No. 71 to our New Mexico jurisdiction. The decision was based on our receiving the NMPRC’s approval for new rates that were based upon our cost of service and the fact that New Mexico had repealed its electric utility restructuring law. The re-application of SFAS No. 71 to our New Mexico jurisdiction resulted in the recording of a $1.8 million extraordinary gain, net of tax, in the third quarter of 2004.

Index to Financial Statements

New accounting standards

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” – an amendment of Accounting Research Bulletin No. 43, (“ARB No. 43”), (“Inventory Pricing”). ARB No. 43 previously stated that “under some circumstances, items such as idle facility expense, excessive spoilage, double freight and rehandling costs may be so abnormal as to require treatment as current period charges.” SFAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not believe SFAS No. 151 will have a significant impact on our consolidated financial statements.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” – an amendment of Accounting Principles Board Opinion No. 29 (“APB No. 29”), “Accounting for Nonmonetary Transactions.” The guidance in APB No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged, with certain exceptions. SFAS No. 153 eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have “commercial substance.” A nonmonentary exchange has “commercial substance” if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for fiscal periods beginning after June 15, 2005. We do not believe SFAS No. 153 will have a significant impact on our consolidated financial statements.

In December 2004, the FASB issued a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (revised) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123 (revised) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award – “the requisite service period” – typically the vesting period. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. SFAS No. 123 (revised) is effective for public entities that do not file as small business issuers as of the beginning of the first interim or annual reporting period that begins after December 15, 2005. SFAS No. 123 (revised) applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of the effective date shall be expensed as the requisite service is rendered on or after the required effective date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. The Company anticipates using the “modified perspective” method of adopting SFAS No. 123 (revised). We have estimated the ultimate impact that this new pronouncement will have on our financial statements to be less than $1.0 million and do not expect this statement to have an effect materially different than the pro forma disclosures provided in Note A “Summary of Significant Accounting Policies and Estimates” to the Notes to Consolidated Financial Statements.

Index to Financial Statements

SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle, such as a change in contractual bonus payments resulting from an accounting change, should be recognized in the period of the accounting change. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle and recognized in the period of change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We will adopt the provisions of SFAS No. 154, if applicable, beginning in 2006.

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

Liquidity and Capital Resources

Our principal liquidity requirements in the near-term are expected to consist of the interest payments on our indebtedness, capital expenditures related to our generating facilities and transmission and distribution systems, operating expenses including fuel costs and taxes. We expect that cash flows from operations will be sufficient for such purposes, assuming that we receive timely recognition of recent increases in natural gas costs in fuel rates. As of December 31, 2005, we had approximately $8.0 million in cash and cash equivalents, a decrease of $21.4 million from the balance of $29.4 million on December 31, 2004.

Capital Requirements. Substantial increases in the cost of natural gas during 2005 and the delay in reflecting higher fuel costs in fixed fuel factors in Texas have led to the under-recovery of the Texas jurisdictional portion of our fuel costs by $84.9 million, including interest, for the period from March 2004 to December 2005. In November 2005, the Texas Commission approved a settlement of a fuel factor filing to (i) surcharge fuel under-recoveries including interest through August 2005 which then totaled $53.6 million; (ii) surcharge the under-recovery over a 24-month period; and (iii) approve new fuel factors which reflected natural gas costs of $7.28 per mmbtu. We had previously been permitted to implement the increase in the fuel factor and the fuel surcharge on an interim basis beginning with October 2005 billings.

In January 2006, we filed a request with the Texas Commission for an additional increase in our fixed fuel factors and to surcharge approximately $34 million for fuel under-recoveries including interest for the period September 2005 to November 2005 over a twelve-month period. The requested fuel factor and fuel surcharge were placed into effect on an interim basis subject to refund effective with February 2006 bills to customers. We are currently negotiating with parties on a settlement to resolve this proceeding. Any settlement will be subject to final approval by the Texas Commission. Until the balance of fuel under-recoveries is recovered from customers, we will be required to finance higher natural gas costs from internal sources of cash rather than use such cash for other purposes.

Our long-term capital requirements consist primarily of construction of electric utility plant and the payment of interest on and refinancing of debt. Utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of steam generators in Palo Verde Unit 3. See Part I, Item 1,

Index to Financial Statements

“Business – Construction Program.” We expect that all of our construction expenditures will be financed with internal sources of funds through 2008.

During the twelve months ended December 31, 2005, we generated $89.2 million of federal income tax loss carryforwards and $42.0 million of state income tax loss carryforwards as a result of (i) increased deferred fuel revenues that are not taxable until collected; (ii) deductible premiums on retired debt; and (iii) increased deductions due to several method changes primarily related to tax depreciation and repair allowances. We anticipate that existing federal and state tax loss carryforwards will be fully utilized in 2006 and our cash flow requirements for federal and state income taxes are expected to increase over that required in recent years.

We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We have contributed $19.9 million and $15.7 million to our retirement plans during the twelve months ended December 31, 2005 and 2004, respectively. We have also contributed $3.4 million to our other postretirement benefit plan for both 2005 and 2004 and $6.2 million and $5.9 million to our decommissioning trust funds during the twelve months ended December 31, 2005 and 2004, respectively.

The Company does not pay dividends on common stock. Since 1999, the Company has repurchased approximately 15.3 million shares of common stock at an aggregate cost of $175.6 million, including commissions, pursuant to a stock repurchase plan. The Board of Directors authorized the repurchase of up to 2 million shares of common stock in February 2004 of which 1,705,158 shares remain available to be repurchased. No shares were repurchased during 2005. We may continue making purchases of our stock pursuant to our stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired. Common stock equity as a percentage of capitalization, including the current portion of long-term debt and financing obligations, was 47% as of December 31, 2005.

Capital Sources. We filed a shelf registration statement on Form S-3 with the SEC which became effective on May 5, 2005. The shelf registration statement enables us to offer and issue debt securities, first mortgage bonds, shares of stock and certain other securities from time to time in one or more offerings of up to $1.0 billion. On May 19, 2005, pursuant to this shelf registration, we issued $400.0 million of 6% Senior Notes (the “Notes”) due May 15, 2035. The proceeds from the issuance of the Notes were $397.7 million, net of a $2.3 million discount and the effective interest rate was 6.2%. In anticipation of issuing the Notes, we entered into treasury rate lock agreements to hedge against potential movements in the treasury reference interest rates. These treasury rate locks expired during the second quarter of 2005. Treasury rates fell after we entered into these agreements, and as a result, we made a cash payment of $22.4 million to settle the treasury rate locks at the termination of these agreements in May 2005, which are being amortized over the term of the related debt.

During the second quarter of 2005, we tendered for and/or exercised our right to legally defease our outstanding 8.90% Series D First Mortgage Bonds due February 1, 2006 and our 9.40% Series E First Mortgage Bonds due May 1, 2011, which were callable beginning on February 1, 2006 (collectively, the “Bonds”). The total principal amount of the outstanding Bonds was approximately $359.4 million. The net proceeds from the issuance of the Notes were used to fund the retirement of the Bonds.

Index to Financial Statements

On August 1, 2005, we issued three series of pollution control bonds in the amounts of $63.5 million, $59.2 million and $37.1 million. The $59.2 million bonds, which mature in 2040, were issued with a fixed interest rate of 4.80% and an effective interest rate of 5.27% after considering related insurance and issuance costs. The $63.5 million and $37.1 million bonds, which also mature in 2040, were issued with a variable rate that is repriced weekly until they mature in 2040. We also remarketed $33.3 million of pollution control bonds, which bear a fixed interest rate of 4% until August 1, 2012, which is the date the bonds are due to be remarketed. The effective interest rate for these bonds is 4.70% after considering related insurance and issuance costs. The issuance and remarketing replaced four series of bonds which were subject to mandatory tender or remarketing as of August 1, 2005.

Our $100 million revolving credit facility provides up to $70 million for nuclear fuel purchases. Any amounts we do not borrow for nuclear fuel purchases are available for working capital needs. As of December 31, 2005, approximately $41.9 million had been drawn for nuclear fuel purchases and no borrowings were outstanding on this facility for working capital needs. The revolving credit facility was renewed for a five-year term in December 2004. During the term of the agreement, the revolving credit facility may be increased to $150 million.

Given the favorable movements of interest rates in the bank markets and the increased volatility that is being experienced in the natural gas markets, we have recently begun the process of replacing our $100 million revolving credit facility with a new $150 million revolving credit facility. The new revolving credit facility will have similar terms to the existing revolving credit facility and will provide up to $70 million for nuclear fuel purchases with any amounts not borrowed for nuclear fuel purchases available for use for working capital. The Company expects, but has no assurance, that the new revolving credit facility will be in place by the second quarter of 2006.

Contractual Obligations. Our contractual obligations as of December 31, 2005 are as follows (in thousands):


	Payments due by period
	Total		2006		2007 and 2008		2009 and 2010		2011 and Beyond
Long-Term Debt (including interest):
Senior notes	$	1,106,000	$	24,000	$	48,000	$	48,000	$	986,000
Pollution control bonds (1)(2)		421,295		7,697		15,394		15,394		382,810
Financing Obligations (including interest):
Nuclear fuel (3)		44,037		22,831		21,206		—		—
Purchase Obligations:
Capacity power contract		264,808		11,320		23,183		23,918		206,387
Fuel contracts:
Coal (4)		78,792		7,504		15,008		15,008		41,272
Gas (4)		91,182		53,419		37,763		—		—
Nuclear fuel (5)		11,404		11,404		—		—		—
Retirement Plans and Other Postretirement Benefits (6)		5,124		5,124		—		—		—
Decommissioning trust funds (7)		266,045		6,686		14,177		16,100		229,082
Operating lease (8)		2,200		1,300		600		300		—

Total	$	2,290,887	$	151,285	$	175,331	$	118,720	$	1,845,551

Index to Financial Statements

(1)	The $33.3 million series of pollution control bonds is scheduled for remarketing in August 2012.

(2)	Two series of the pollution control bonds are remarketed and the interest rates are set weekly. The remaining two series of pollution control bonds are scheduled for remarketing and/or mandatory tender in 2012 and 2040.

(3)	Interest on nuclear fuel is based on actual interest rates at the end of 2005.

(4)	Amount is based on the minimum volumes per the contract and market price at the end of 2005. Gas obligation includes a gas storage contract for 2006 and 2007, with an option to renew annually.

(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 2005.

(6)

These obligations include our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2006. We have no minimum contractual funding requirement related to our retirement income plan for 2006. However, we may decide to fund at a higher level than the minimum contractual funding amounts and expect to contribute $13.7 million and $3.4 million to our retirement plans and postretirement benefit plan in 2006, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note K, Employee Benefits. Minimum contractual funding requirements for 2007 and beyond are not included due to the uncertainty of interest rates and the related return on assets.

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

(8)	We have an operating lease for administrative offices which expires in May 2007 and a four-year operating lease for a warehouse which expires in December 2009 with three concurrent renewal options of one year each.

Off-Balance Sheet Arrangements

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

Index to Financial Statements

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

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

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

Interest Rate Risk

Our long-term debt obligations are all fixed-rate obligations with varying maturities, except for two of our pollution control bond series which are repriced weekly and our revolving credit facility, which provides for nuclear fuel financing and working capital, and is based on floating rates.

On August 1, 2005, we issued two series of pollution control bonds in the amounts of $63.5 million and $37.1 million with a variable rate that is repriced weekly until they mature in 2040. These pollution control bonds are carried on the balance sheet at their face value. At December 31, 2005 the variable interest rates were 3.60% and 3.25% for the $63.5 million and the $37.1 million pollution control bond series, respectively. A hypothetical 10% increase in interest rates, annualized from the December 31, 2005 rate, would cause an approximate $0.3 million increase in interest expense.

Interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the Texas Commission and NMPRC rules which establish energy cost recovery clauses (“fuel clauses”). Under these rules and fuel clauses, energy costs, including interest expense on nuclear fuel financing, except as noted in “Regulation – New Mexico Regulatory Matters – Fuel,” are passed through to customers.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at market value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $39.3 million and $57.3 million as of December 31, 2005 and 2004, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.6 million and $0.8 million based on their fair values at December 31, 2005 and 2004, respectively.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $56.7 million and $32.1 million at December 31, 2005 and 2004, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $11.3 million and $6.4 million based on their fair values at December 31, 2005 and 2004, respectively.

Index to Financial Statements

Commodity Price Risk

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

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. They also include forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2006, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, “Business – Energy Sources – Purchased Power” and “Regulation – Power Sales Contracts.” These agreements are generally fixed-priced contracts which qualify for the “normal purchases and normal sales” exception provided in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group and are not recorded at their fair value in our financial statements. Because of the operation of the Texas Commission and NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

Index to Financial Statements

Management Report on Internal Control Over Financial Reporting

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

•

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

•

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

•

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

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

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework.

Based on its assessment, management believes that, as of December 31, 2005, the Company’s internal control over financial reporting is effective based on those criteria.

The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting. This report appears on page 52 of this report.

Index to Financial Statements

Item 8.

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS


		Page
Reports of Independent Registered Public Accounting Firm		51

Consolidated Balance Sheets at December 31, 2005 and 2004		54

Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003		56

Consolidated Statements of Comprehensive Operations for the years ended December 31, 2005, 2004 and 2003		57

Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2005, 2004 and 2003		58

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		59

Notes to Consolidated Financial Statements		60

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2005 and 2004, 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, 2005. 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 the standards of the Public Company Accounting Oversight Board (United States). 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note D to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in 2005 and 2003.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of El Paso Electric Company’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 10, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

El Paso, Texas

March 10, 2006

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

El Paso Electric Company:

We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions (COSO). El Paso Electric Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, management’s assessment that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by COSO.

Index to Financial Statements

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2005 and 2004, 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, 2005, and our report dated March 10, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

El Paso, Texas

March 10, 2006

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS


ASSETS	December 31,
(In thousands)	2005			2004
Utility plant:
Electric plant in service	$	1,913,196		$	1,839,924
Less accumulated depreciation and amortization		(740,339	)		(666,774	)

Net plant in service		1,172,857			1,173,150
Construction work in progress		83,092			72,273
Nuclear fuel; includes fuel in process of $6,990 and $7,128, respectively		66,516			69,239
Less accumulated amortization		(30,768	)		(34,195	)

Net nuclear fuel		35,748			35,044

Net utility plant		1,291,697			1,280,467

Current assets:
Cash and temporary investments		7,956			29,401
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,474 and $3,071, respectively		76,006			70,710
Accumulated deferred income taxes		2,628			6,509
Inventories, at cost		28,553			27,773
Under collection of fuel revenues		71,611			18,782
Income taxes receivables		16,349			14,919
Prepayments and other		8,463			11,587

Total current assets		211,566			179,681

Deferred charges and other assets:
Decommissioning trust funds		96,010			89,363
Regulatory assets		26,050			18,487
Under collection of fuel revenues, non-current		20,720			—
Other		19,406			12,837

Total deferred charges and other assets		162,186			120,687

Total assets	$	1,665,449		$	1,580,835

See accompanying notes to consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS (Continued)


CAPITALIZATION AND LIABILITIES	December 31,
(In thousands)	2005			2004
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 63,382,456 and 62,665,550 shares issued, and 124,973 and 102,630 restricted shares, respectively	$	63,507		$	62,768
Capital in excess of stated value		275,393			268,771
Deferred and unearned compensation		2,150			1,127
Retained earnings		421,632			386,110
Accumulated other comprehensive loss, net of tax		(30,167	)		(10,553	)

		732,515			708,223
Treasury stock, 15,365,108 shares at cost		(176,076	)		(176,076	)

Common stock equity		556,439			532,147
Long-term debt, net of current portion		590,838			359,362
Financing obligations, net of current portion		20,180			20,274

Total capitalization		1,167,457			911,783

Current liabilities:
Current portion of long-term debt and financing obligations		21,727			214,092
Accounts payable, principally trade		47,128			34,404
Taxes accrued other than federal income taxes		16,021			15,719
Interest accrued		4,484			13,609
Other		24,165			24,726

Total current liabilities		113,525			302,550

Deferred credits and other liabilities:
Accumulated deferred income taxes		123,233			111,991
Accrued postretirement benefit liability		105,084			98,827
Asset retirement obligation		66,997			60,388
Accrued pension liability		45,952			49,055
Regulatory liabilities		15,817			15,682
Other		27,384			30,559

Total deferred credits and other liabilities		384,467			366,502

Commitments and contingencies
Total capitalization and liabilities	$	1,665,449		$	1,580,835

See accompanying notes to consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands except for share data)


	Years Ended December 31,
	2005			2004			2003
Operating revenues	$	803,913		$	708,628		$	664,362

Energy expenses:
Fuel		262,870			194,424			165,367
Purchased and interchanged power		80,040			66,451			55,592

		342,910			260,875			220,959

Operating revenues net of energy expenses		461,003			447,753			443,403

Other operating expenses:
Other operations		178,287			173,536			167,862
Maintenance		47,338			45,190			48,246
Impairment loss on CIS project		—			—			17,576
Depreciation and amortization		82,468			93,372			87,621
Taxes other than income taxes		45,027			42,584			42,728

		353,120			354,682			364,033

Operating income		107,883			93,071			79,370

Other income (deductions):
Investment and interest income, net		5,625			3,404			1,840
Loss on extinguishments of debt		(19,561	)		(5,356	)		(1	)
Miscellaneous non-operating income		1,121			859			1,378
Miscellaneous non-operating deductions		(4,186	)		(3,135	)		(2,509	)

		(17,001	)		(4,228	)		708

Interest charges (credits):
Interest on long-term debt and financing obligations		40,762			49,168			51,400
Other interest		699			535			695
Capitalized interest and AFUDC		(5,783	)		(3,427	)		(5,572	)

		35,678			46,276			46,523

Income before income taxes, cumulative effect of accounting change and extraordinary item		55,204			42,567			33,555
Income tax expense		18,589			9,198			13,233

Income before cumulative effect of accounting change and extraordinary item		36,615			33,369			20,322
Cumulative effect of accounting change, net of tax		(1,093	)		—			39,635
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			1,802			—

Net income	$	35,522		$	35,171		$	59,957

Basic earnings (losses) per share:
Income before cumulative effect of accounting change and extraordinary item	$	0.77		$	0.70		$	0.42
Cumulative effect of accounting change, net of tax		(0.02	)		—			0.82
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			0.04			—

Net income	$	0.75		$	0.74		$	1.24

Diluted earnings (losses) per share:
Income before cumulative effect of accounting change and extraordinary item	$	0.76		$	0.69		$	0.42
Cumulative effect of accounting change, net of tax		(0.02	)		—			0.81
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			0.04			—

Net income	$	0.74		$	0.73		$	1.23

Weighted average number of shares outstanding		47,711,894			47,426,813			48,424,212

Weighted average number of shares and dilutive potential shares outstanding		48,307,910			48,019,721			48,814,761

See accompanying notes to consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)


	Years Ended December 31,
	2005			2004			2003
Net income	$	35,522		$	35,171		$	59,957
Other comprehensive income (loss):
Minimum pension liability adjustment		(6,128	)		(1,413	)		(4,234	)
Net unrealized gains (losses) on marketable securities:
Net holding gains (losses) arising during period		(1,795	)		351			8,764
Reclassification adjustments for net (gains) losses included in net income		(564	)		(425	)		722
Net losses on cash flow hedges:
Losses arising during period		(22,439	)		—			—
Reclassification adjustment for interest expense included in net income		143			—			—

Total other comprehensive income (loss) before income taxes		(30,783	)		(1,487	)		5,252

Income tax benefit (expense) related to items of other comprehensive income (loss):
Minimum pension liability adjustment		2,299			532			1,673
Net unrealized gains (losses) on marketable securities		472			15			(2,117	)
Losses on cash flow hedges		8,398			—			—

Total income tax benefit (expense)		11,169			547			(444	)

Other comprehensive income (loss), net of tax		(19,614	)		(940	)		4,808

Comprehensive income	$	15,908		$	34,231		$	64,765

See accompanying notes to consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(In thousands except for share data)


						Capital in Excess of Stated Value			Deferred and Unearned Compensation			Retained Earnings		Accumulated Other Comprehensive Income (Loss), Net of Tax							Total Common Stock Equity


	Common Stock																Treasury Stock
	Shares		Amount														Shares	Amount
Balances at December 31, 2002	62,592,461		$	62,592		$	262,480		$	(1,442	)	$	290,982	$	(14,421	)	12,982,995	$	(147,309	)	$	452,882
Grants of restricted common stock	63,090			63			661			(724	)											—
Deferred compensation-restricted stock										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													59,957									59,957
Other comprehensive income															4,808							4,808
Treasury stock acquired, at cost																	2,087,271		(24,239	)		(24,239	)

Balances at December 31, 2003	62,633,752			62,633			264,235			(878	)		350,939		(9,613	)	15,070,266		(171,548	)		495,768
Grants of restricted common stock	56,413			56			756			(812	)											—
Deferred compensation-restricted stock and performance shares										2,804												2,804
Stock awards withheld for taxes	(12,753	)		(12	)		(160	)														(172	)
Forfeitures of restricted common stock	(1,074	)		(1	)		(12	)		13												—
Deferred taxes on stock incentive plan							(409	)														(409	)
Stock options exercised	91,842			92			981															1,073
Adjustment to federal valuation allowance							3,380															3,380
Net income													35,171									35,171
Other comprehensive loss															(940	)						(940	)
Treasury stock acquired, at cost																	294,842		(4,528	)		(4,528	)

Balances at December 31, 2004	62,768,180			62,768			268,771			1,127			386,110		(10,553	)	15,365,108		(176,076	)		532,147
Grants of restricted common stock	104,907			105			1,870			(1,975	)											—
Deferred compensation-restricted stock and performance shares										2,926												2,926
Stock awards withheld for taxes	(7,907	)		(8	)		(144	)														(152	)
Forfeitures of restricted common stock	(4,251	)		(4	)		(68	)		72												—
Deferred taxes on stock incentive plan							170															170
Stock options exercised	646,500			646			4,794															5,440
Net income													35,522									35,522
Other comprehensive loss															(19,614	)						(19,614	)

Balances at December 31, 2005	63,507,429		$	63,507		$	275,393		$	2,150		$	421,632	$	(30,167	)	15,365,108	$	(176,076	)	$	556,439

See accompanying notes to consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Years Ended December 31,
	2005			2004			2003
Cash Flows From Operating Activities:
Net income	$	35,522		$	35,171		$	59,957
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service		82,468			93,372			87,621
Impairment loss on CIS project		—			—			17,576
Amortization of nuclear fuel		15,575			17,226			16,374
Cumulative effect of accounting change, net of tax		1,093			—			(39,635	)
Extraordinary gain on the re-application of SFAS No. 71, net of tax		—			(1,802	)		—
Deferred income taxes, net		25,286			401			10,063
Loss on extinguishments of debt		19,561			5,356			1
Other amortization and accretion		11,961			10,851			7,744
Gain on sale of asset		(374	)		—			—
Other operating activities		(110	)		(414	)		1,432
Change in:
FERC settlements payable		—			—			(15,500	)
Accounts receivable		(5,296	)		(4,121	)		(1,258	)
Inventories		(758	)		6			233
Net (under)/overcollection of fuel revenues		(73,549	)		(16,453	)		16,476
Prepayments and other		(174	)		(1,787	)		(17,687	)
Accounts payable		12,724			15,207			(5,702	)
Taxes accrued other than federal income taxes		302			552			(2,660	)
Interest accrued		(9,125	)		(1,097	)		(1,259	)
Other current liabilities		(561	)		(2,663	)		225
Deferred charges and credits		(7,840	)		(6,126	)		1,612

Net cash provided by operating activities		106,705			143,679			135,613

Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment		(88,263	)		(72,092	)		(77,679	)
Cash additions to nuclear fuel		(15,888	)		(15,828	)		(13,848	)
Proceeds from sale of asset		1,944			—			—
Capitalized interest and AFUDC:
Utility property, plant and equipment		(5,330	)		(3,144	)		(5,322	)
Nuclear fuel		(453	)		(283	)		(250	)
Decommissioning trust funds:
Purchases, including funding of $6.2 million, $5.9 million and $10.4 million, respectively		(42,381	)		(44,640	)		(21,079	)
Sales and maturities		33,451			36,434			9,384
Other investing activities		(882	)		(2,808	)		1,467

Net cash used for investing activities		(117,802	)		(102,361	)		(107,327	)

Cash Flows From Financing Activities:
Proceeds from exercise of stock options		5,440			1,073			—
Repurchases of treasury stock		—			(4,528	)		(24,239	)
Settlement on derivative instruments classified as cash flow hedges		(22,439	)		—			—
Proceeds from issuance of long-term notes payable		397,688			—			—
Repurchases of and payments on first mortgage bonds		(381,847	)		(41,048	)		(39,360	)
Pollution control bonds:
Proceeds		193,135			—			—
Payments		(193,135	)		—			—
Financing obligations:
Proceeds		18,138			17,123			15,169
Payments		(17,427	)		(18,102	)		(20,207	)
Other financing activities		(9,901	)		(861	)		(365	)

Net cash used for financing activities		(10,348	)		(46,343	)		(69,002	)

Net decrease in cash and temporary investments		(21,445	)		(5,025	)		(40,716	)
Cash and temporary investments at beginning of period		29,401			34,426			75,142

Cash and temporary investments at end of period	$	7,956		$	29,401		$	34,426

See accompanying notes to consolidated financial statements.

Index to Financial Statements

INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Note A. Summary of Critical Accounting Policies		61

Note B. Regulation		69

Note C. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant		77

Note D. Accounting for Asset Retirement Obligations		82

Note E. Common Stock		84

Note F. Accumulated Other Comprehensive Income (Loss)		89

Note G. Long-Term Debt and Financing Obligations		90

Note H. Income Taxes		93

Note I. Commitments, Contingencies and Uncertainties		96

Note J. Litigation		99

Note K. Employee Benefits		101

Note L. Franchises and Significant Customers		111

Note M. Financial Instruments and Investments		111

Note N. Supplemental Statements of Cash Flow Disclosures		114

Note O. Selected Quarterly Financial Data (Unaudited)		115

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A.	Summary of Significant Accounting Policies

General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. El Paso Electric Company also serves 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 sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. See Note 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”).

Application of SFAS No. 71. Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Under this accounting standard, certain recoverable costs are shown as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from its customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utility’s cost of service.

Beginning in 1991, the Company discontinued the application of SFAS No. 71 to its financial statements. This decision was based on the Company’s determination that its rates were no longer designed to recover its costs of providing service to customers. Upon emerging from bankruptcy in 1996, the Company again concluded that it did not meet the criteria for applying SFAS No. 71 because of the ten-year rate freeze in Texas and its ongoing intention not to seek changes in its New Mexico rates, which had been established in 1990. Although the Company believes the rates established in 1995 were based upon its costs of service, the unusual length of the rate freeze period created substantial uncertainty as to the ultimate recovery of its costs over the entire freeze period. Consequently, the

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company determined that it should not re-apply SFAS No. 71 to its Texas and New Mexico jurisdictions at the time it emerged from bankruptcy in February 1996.

During 2004, the Company determined that it met the criteria necessary to re-apply SFAS No. 71 to its New Mexico jurisdictional operations. Two key events transpired in New Mexico that, when considered together, resulted in the Company’s decision to re-apply SFAS No. 71. In April of 2004, the Company received a final order approving a unanimous stipulation which established new base and fuel rates for its New Mexico customers which were implemented on June 1, 2004. The Company’s approved rates were based upon its cost of providing service in New Mexico. That event, coupled with the repeal of New Mexico’s electric utility industry restructuring law which occurred in April 2003, resulted in the Company meeting the criteria for the re-application of SFAS No. 71 to New Mexico, beginning July 1, 2004. The re-application of SFAS No. 71 to the Company’s New Mexico jurisdiction resulted in the recording of $18.5 million of regulatory assets, $5.0 million in related accumulated deferred income tax assets, $16.2 million of regulatory liabilities, $5.5 million in related accumulated deferred tax liabilities and a $1.8 million extraordinary gain, net of tax, or $0.04 basic and diluted earnings per share.

The Company has not reapplied SFAS No. 71 to its Texas jurisdiction. However, the Company is currently evaluating the reapplication of SFAS No. 71 to its Texas jurisdiction based upon the expiration of the ten year rate freeze in Texas, the delay of retail competition in 2004, and a new rate settlement agreement with the City of El Paso (“City”). In July 2005, the Company entered into a settlement agreement with the City (“City Rate Agreement”) which provides for a new rate freeze (“New Texas Freeze Period”) until June 30, 2010. The City Rate Agreement specifically provides for the Company’s rates to be cost based. If the Company’s return on equity falls below a range around a calculated return on equity under current market conditions during the New Texas Freeze Period, the Company may seek to increase rates. Likewise, if the Company’s return on equity exceeds the range, 50% of the excess must be paid to the City. The City Rate Agreement provides for the City to conduct a review of the Company’s operating expenses and provides for revision of the rate agreement if they are not determined to be within a reasonable range compared to the utility industry. Also, the City Rate Agreement provides for the Company to retain 75% of off-system sales margins rather than the previous 50%. While the City Rate Agreement has been approved by the City, in order to fully implement the agreement, the Texas Commission must approve the sharing of off-system sales margins provisions of the agreement and, in effect, the entire agreement for the Texas customers outside the City. Once the City Rate Agreement is approved by the Texas Commission, the Company will complete the evaluation as to whether SFAS No. 71 should be reapplied to its Texas jurisdiction. The re-application of SFAS No. 71 will result in the recognition of regulatory assets and liabilities that could have a material effect on our consolidated financial statements. However, the re-application of SFAS No. 71 will have no effect on our cash flow.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Comprehensive Income. Certain gains and losses that are not recognized currently in the consolidated statements of operations are reported as other comprehensive income in accordance with SFAS No. 130, “Reporting Comprehensive Income.”

Utility Plant. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from 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 was depreciated on a straight-line basis over the ten-year period of the Texas Rate Stipulation which ended in July 2005. For all other utility plant, Texas and New Mexico depreciation lives are the same.

In conjunction with a certain regulatory filing in the New Mexico jurisdiction, the Company implemented new depreciation rates effective January 1, 2004. The new rates had the effect of increasing depreciation and amortization expense by approximately $1.9 million and decreasing net income, after tax, by approximately $1.2 million or $.03 basic and diluted earnings per share for the year ending December 31, 2004 compared to the year ended December 31, 2003.

The Company charges the cost of repairs and minor replacements to the appropriate operating expense accounts and capitalizes the cost of renewals and betterments. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on 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 estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

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” for its Texas jurisdictional operations. For its New Mexico jurisdictional operations, the Company capitalizes interest

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and common equity costs to construction work in progress and nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in SFAS No. 71. The amount of the equity component of the AFUDC capitalized to construction work in progress was $0.9 million and $0.3 million for the years ended December 31, 2005 and 2004, respectively.

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. In January 2003 the Company began recording the increase in the ARO due to the passage of time as an operating expense (accretion expense). Effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies that the term “conditional” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity even if the timing and/or settlement are conditional on a future event that may or may not be within the control of an entity. See Note D.

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

Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair 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.

Derivative Accounting. 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 FASB Derivatives Implementation Group. This standard requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Note M.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Public Utility Commission of Texas (“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, as approved by the New Mexico Public Regulation Commission (“NMPRC”) in June 2004. 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 Commission and NMPRC rules, is reflected as net over/undercollection of fuel revenues in the consolidated balance sheets. See Note B. Amounts not expected to be collected within the next twelve months are classified as “undercollection of fuel revenues, non-current.”

Unbilled Revenues. Accounts receivable include accrued unbilled revenues of $16.4 million and $18.0 million at December 31, 2005 and 2004, respectively.

Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2005, 2004 and 2003 are as follows (in thousands):


	2005		2004		2003
Balance at beginning of year	$	3,071	$	3,470	$	3,234
Additions:
Charged to costs and expense		2,527		1,999		3,096
Recovery of previous write-offs		1,195		1,422		981
Uncollectible receivables written off		4,319		3,820		3,841

Balance at end of year	$	2,474	$	3,071	$	3,470

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 statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The 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.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 restricted stock determined at the date of grant over the restriction period of the grant. 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,
	2005		2004		2003
Net income, as reported	$	35,522	$	35,171	$	59,957
Deduct: Compensation expense, net of tax		806		894		916

Pro forma net income	$	34,716	$	34,277	$	59,041

Basic earnings per share:
As reported	$	0.75	$	0.74	$	1.24
Pro forma		0.73		0.72		1.22
Diluted earnings per share:
As reported		0.74		0.73		1.23
Pro forma		0.72		0.71		1.21

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. No stock options were granted in 2005. Weighted average assumptions and grant-date fair value for 2004 and 2003 are presented below:


	2004			2003
Risk-free interest rate		4.01	%		4.13	%
Expected life, in years		7.3			7.4
Expected volatility		22.42	%		24.72	%
Expected dividend yield		—			—
Fair value per option	$	4.87		$	4.83

Restricted Stock. Restricted stock has been granted at fair market value. 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 a reduction of common stock equity and included in deferred and unearned compensation on the Company’s consolidated balance sheets.

Performance Shares. Subject to meeting certain performance criteria, performance shares will be granted to certain officers under the Company’s existing long-term incentive plan on January 1, 2006 and 2007. The Company currently recognizes the related compensation expense by ratably amortizing the current fair market value of awards that would be granted based on the current performance of the Company over the performance cycles. Consistent with the provisions of APB Opinion No. 25, compensation expense for performance shares determined using the intrinsic value method will be adjusted for subsequent changes (such as the number of shares to be granted, if any, and the fair market value of the Company’s stock) in the expected outcome of the performance-related conditions until the end of the performance cycle. Any such adjustments are accounted for as a change in estimate, and the cumulative effect of the change on current and prior periods is recognized in the period of the change.

Other New Accounting Standards. In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” – an amendment of Accounting Research Bulletin No. 43 (“ARB No. 43”), (“Inventory Pricing”). ARB No. 43 previously stated that “under some circumstances, items such as idle facility expense, excessive spoilage, double freight and rehandling costs may be so abnormal as to require treatment as current period charges.” SFAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not believe SFAS No. 151 will have a significant impact on the Company’s consolidated financial statements.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have “commercial substance.” A nonmonetary exchange has “commercial substance” if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not believe SFAS No. 153 will have a significant impact on the Company’s consolidated financial statements.

In December 2004, the FASB issued a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (revised) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123 (revised) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award – “the requisite service period” – typically the vesting period. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. SFAS No. 123 (revised) is effective for public entities that do not file as small business issuers as of the beginning of the first interim or annual reporting period that begins after December 15, 2005. SFAS No. 123 (revised) applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of the effective date shall be expensed as the requisite service is rendered on or after the required effective date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. The Company anticipates using the “modified perspective” method of adopting SFAS No. 123 (revised). The Company has estimated the ultimate impact that this new pronouncement will have on its financial statements to be less than $1.0 million and do not expect this statement to have an effect materially different than the pro forma disclosures provided above.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20, and FASB Statement No. 3.” SFAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle, such as a change in contractual bonus payments resulting from an accounting change, should be recognized in the period of the accounting change. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate affected by a change in accounting principle and recognized in the period of change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company will adopt the provisions of SFAS No. 154, if applicable, beginning in 2006.

Reclassification. Certain amounts in the consolidated financial statements for 2004 and 2003 have been reclassified to conform with the 2005 presentation.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

B.	Regulation

General

Federal Regulatory Matters

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the Western Grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company, however, is approximately a 7% participant in WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years. The establishment of an independent RTO in the Company’s service area is a prerequisite for the Company to be considered part of a Qualified Power Region as defined in the Texas Restructuring Law. The timing of the operations of WestConnect will affect when and whether the Company’s Texas service territory is deregulated under the Texas Restructuring Law.

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.

Texas Regulatory Matters

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of an RTO in the area that includes the Company’s service territory, including the development of retail market protocols to facilitate retail competition. The complete transition to retail competition would occur upon the completion of the last milestone, which would be the Texas Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes that adoption of this rule will likely delay retail competition in El Paso for a number of years. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory, and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect the future operations, cash flows and financial condition of the Company.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

adjustment to base rates. If the Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The range is market-based, and at current rates, would be a range of approximately 8% to 12%.

The Company reconciled its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001 in PUC Docket No. 26194, and on May 5, 2004, the Texas Commission

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

issued its final order. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge due to 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. This disallowance was recorded as a reduction of fuel revenue during the fourth quarter of 2003. 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 period in which the imputed capacity charges were deemed to have been incurred, the $4.2 million of imputed capacity charges were therefore permanently disallowed and not recoverable from its Texas customers. The Texas Commission’s decision has been appealed by two parties and the Company, and the Company is unable to predict the ultimate outcome of the appeals.

On August 31, 2004, the Company filed an application to reconcile Texas jurisdictional fuel costs for the period January 1, 2002 through February 29, 2004 in PUC Docket No. 30143. The Company has incurred purchased power costs similar to those that were at issue in PUC Docket No. 26194 during the period covered by this fuel reconciliation case. The Company believes that it has accounted for its purchased power costs during the reconciliation period covered by PUC Docket No. 30143 in a manner consistent with the Texas Commission’s decision in PUC Docket No. 26194. However, the Texas Commission is currently conducting a generic rulemaking proceeding to determine a statewide policy for the appropriate recovery mechanism for such capacity costs in purchased power contracts. There can be no assurance as to the outcome of the rulemaking and its potential impact on the Company with respect to fuel recovery in future reconciliation periods, including that in PUC Docket No. 30143. Additionally, intervenors in PUC Docket No. 30143 filed testimony disputing as much as $44 million of the requested fuel and purchased power costs. A stipulation resolving all issues in the fuel reconciliation was filed on January 27, 2006. The stipulation provides for a $9.0 million disallowance of the eligible fuel costs requested by the Company. The Company recorded a reserve including $1.5 million in the third quarter of 2005, sufficient to provide for the stipulated $9.0 million in fuel disallowances in PUC Docket No. 30143. The Texas Commission approved a final order on March 8, 2006, which was consistent with the stipulation.

On July 8, 2005, the Company filed a petition (PUC Docket No. 31332) with the Texas Commission to increase its fixed fuel factors and to surcharge under-recovered fuel costs as a result of higher natural gas prices. The Company requested an increase in its Texas jurisdiction fixed fuel factors of $30.6 million or 23% annually to reflect an average cost of natural gas costs of $7.28 per MMBtu. The Company also requested a fuel surcharge to recover over a twelve month period $28.2 million of fuel undercollections through the end of May 2005. On September 13, 2005, the Company amended its petition to seek additional fuel under-recoveries through August 2005 and requested that the total fuel under-recoveries of $53.6 million, including interest as of the end of the under-recovery period, be surcharged over a 24-month period. On September 14, 2005, the Company filed a unanimous stipulation

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to approve the requested fixed fuel factor and amended fuel surcharge. The fixed fuel factor and surcharge were implemented effective with billings in October 2005 and final approval from the Texas Commission was received in November 2005.

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 parties to the City Rate Agreement can urge different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. Under the performance standards the Company has not earned a performance reward nor incurred a penalty for the 2005 reporting period. The Company has calculated the performance rewards for the reporting periods ending in 2004 and 2003 to be approximately $0.2 million and $0.8 million, respectively. The 2003 reward was included in the Texas fuel reconciliation in PUC Docket No. 30143, along with energy costs incurred and fuel revenues billed. The 2004 reward will be included along with energy costs incurred and fuel revenue 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.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers.

New Mexico Regulatory Matters

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.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company expects a final order in this case in the first half of 2006. While the Company believes that it has fully supported the recovery of all of its applicable fuel and purchased power costs, the Company cannot predict when or how the NMPRC will rule on this case. An adverse ruling by the NMPRC could have a material negative effect on the Company’s results of operations.

Sales for Resale

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The table below presents the balance of each major class of depreciable assets at December 31, 2005 (in thousands):


	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	633,620	$	(136,119	)	$	497,501
Steam and other		263,901		(135,475	)		128,426

Total production		897,521		(271,594	)		625,927
Transmission		342,971		(211,907	)		131,064
Distribution		582,579		(227,653	)		354,926
General		70,489		(25,040	)		45,449
Intangible and other		19,636		(4,145	)		15,491

Total	$	1,913,196	$	(740,339	)	$	1,172,857

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 10 years). The amortization expense for intangible plant was $1.9 million, $0.9 million and $0.8 million for 2005, 2004 and 2003, respectively. The table below presents the estimated amortization expense for the next five years (in thousands):


2006	$	2,653
2007		2,482
2008		2,124
2009		1,787
2010		1,481

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 Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s consolidated statements of operations. The ANPP

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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, 2005 and 2004 is as follows (in thousands):


	December 31, 2005						December 31, 2004
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	633,620		$	188,049		$	596,371		$	186,838
Accumulated depreciation		(136,119	)		(133,507	)		(121,563	)		(124,146	)
Construction work in progress		28,501			3,814			32,385			4,177

Total	$	526,002		$	58,356		$	507,193		$	66,869

Palo Verde

The Company has established external trusts with an independent trustee, which enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded. As of December 31, 2005 and 2004, the fair market value of the trust funds was approximately $96.0 million and $89.4 million, respectively, which is reflected in the Company’s consolidated balance sheets in deferred charges and other assets.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company needed to fund approximately $311.6 million (stated in 2001 dollars). Had an equivalent estimate been calculated for the 2001 study in 2004 dollars, based upon the same 3.6% escalation rate utilized in 2001 study, the previous estimate would have been $346.5 million. See “Spent Fuel Storage” below.

Historically, regulated utilities such as the Company have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning. The Company, through an affiliated transmission and distribution utility, will be able to continue to collect from customers the costs of decommissioning if and when it becomes subject to the Texas Restructuring Law. 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 Note B “Texas Regulatory Matters – Deregulation” for further discussion.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

generated from nuclear fuel resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. The Company estimates that the reduced output and upcoming outages at Palo Verde Unit 1, together with lower than originally forecast wholesale energy prices, will result in reduced off-system sales margins of approximately $12 to $18 million for the period January through July 2006. The Company cautions that results would differ from its estimates to the extent that actual market prices, Palo Verde Unit 1 operations and other factors vary from its assumptions. The adverse financial impact on the Company from continued reduced output and outages from Palo Verde Unit 1 could increase and would include foregone off-system sales margins, higher capital and/or operating costs and increased purchased power and other costs.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

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. Beginning in 1996 and through 2002, 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. In January 2003, the Company began recording the increase in the ARO due to the passage of time as an operating expense (accretion expense). 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 an independent trustee which are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2005 is $96.0 million.

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


	Years Ended December 31,
	2005			2004		2003
ARO liability at beginning of year	$	60,388		$	55,149	$	50,364
Liabilities incurred		2,719	(1)		—		—
Liabilities settled		—			—		—
Revisions to estimate		(1,767	)		—		—
Accretion expense		5,657			5,239		4,785

ARO liability at end of year	$	66,997		$	60,388	$	55,149

(1)	Results from the implementation of FIN 47 (see discussion below).

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

In 2005, the Palo Verde Participants approved the 2004 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 2001 study and the 2004 study. The 2004 study estimated that the Company must fund approximately $335.7 million (stated in 2004 dollars) to cover its share of decommissioning costs. The previous cost estimate from the 2001 study estimated that the Company needed to fund approximately $311.6 million (stated in 2001 dollars). Had an equivalent estimate been calculated for the 2001 study in 2004 dollars, based upon the same 3.6% escalation rate utilized in the 2001 study, the previous estimate would have been $346.5 million. The estimated liability under the 2004 study differs from the ARO liability of $63.5 million the Company recorded as of December 31, 2005. 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 the original calculation of the ARO liability, the ARO liability is less than the Company’s share of the current estimated cost to decommission Palo Verde in 2004 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.

SFAS No. 143 requires the Company to revise its previously recorded ARO for any changes in estimated cash flows. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows results in a reduction to the previously recorded ARO. Since the 2004 study reflects a downward revision in the estimated cash flows for decommissioning costs from the 2001 study, the Company recorded a $1.8 million reduction to its ARO asset and liability in the third quarter of 2005. Accretion and depreciation expense related to the ARO will decrease approximately $0.3 million annually as a result of this adjustment.

Effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies that the term “conditional” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity even if the timing and/or settlement are conditional on a future event that may or may not be within the control of an entity. Accordingly, the entity must record a liability for the conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. The adoption of FIN 47 primarily affected the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells,

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

evaporative ponds and asbestos found at the Company’s gas-fired generating plants. With the adoption of FIN 47 at December 31, 2005, the Company recognized an increase in its ARO of $2.7 million, an increase in net plant in service of $0.9 million, and a cumulative effect of accounting change resulting in a loss of $1.1 million, net of related taxes. As of December 31, 2004 and 2003, the pro forma ARO liability related to FIN 47 would have been $2.6 million and $2.5 million, respectively.

Amounts recorded under SFAS No. 143 including amounts recorded under FIN 47 are subject to various assumptions and determinations such as (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. 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.

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’s 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 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 2005, 2004 and 2003:

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Number of Shares		Weighted Average Exercise Price
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
Options granted	3,520			13.64
Options exercised	(91,842	)		11.69
Options forfeited	(2,184	)		15.87

Unexercised options outstanding at December 31, 2004	2,080,948			10.40
Options exercised	(646,500	)		8.42
Options forfeited	(80,000	)		14.08

Unexercised options outstanding at December 31, 2005	1,354,448			11.12

Stock option awards provide for vesting periods of up to six years. Stock options outstanding and exercisable at December 31, 2005 are set forth in the following table:


	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 - $8.125	480,000	1.4	$	6.97	480,000	$	6.97
9.50 - 13.85	549,448	6.1		12.85	329,448		12.64
13.94 - 14.95	325,000	5.5		14.35	235,000		14.37

	1,354,448				1,044,448

The number of stock options exercisable and the weighted average exercise price of these stock options are as follows:


	December 31,
	2005		2004		2003
Number of stock options exercisable		1,044,448		1,472,948		1,325,454
Weighted average exercise price	$	10.42	$	9.07	$	8.36

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 three 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 date of grant is recorded as deferred and unearned compensation and is shown as a separate component of common stock equity and is amortized to expense over the restriction period. During 2005, 2004 and 2003, approximately

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

$1.4 million, $1.2 million and $1.3 million, respectively, related to restricted stock awards was charged to expense. The following table summarizes the vested and unvested restricted stock awards for 2005, 2004 and 2003:


	Vested	Unvested		Total
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
Restricted stock awards	—	56,413		56,413
Lapsed restrictions and vesting	—	(99,198	)	(99,198	)
Forfeitures	—	(1,074	)	(1,074	)

Restricted shares outstanding at December 31, 2004	—	102,630		102,630
Restricted stock awards	—	104,907		104,907
Lapsed restrictions and vesting	—	(78,313	)	(78,313	)
Forfeitures	—	(4,251	)	(4,251	)

Restricted shares outstanding at December 31, 2005	—	124,973		124,973

The weighted average market values at grant date for restricted stock awarded during 2005, 2004 and 2003 are $18.82, $14.40 and $11.47, respectively.

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

Performance Shares. On January 1, 2006 and 2007, subject to meeting certain performance criteria, performance shares will be granted to certain officers under the Company’s existing long-term incentive plan. The Company currently recognizes the related compensation expense by ratably amortizing the current fair market value of awards that would be granted based on the current performance of the Company over the performance cycles. Consistent with the provisions of APB Opinion No. 25, compensation expense for performance shares determined using the intrinsic value method will be adjusted for subsequent changes (such as the number of shares to be granted, if any, and the fair market value of the Company’s stock) in the expected outcome of the performance-related conditions until the end of the performance cycle. Any such adjustments are accounted for as a change in estimate, and the cumulative effect of the change on current and prior periods is recognized in the period of the change. The actual number of shares granted can range from zero to 285,000 shares. During 2005 and 2004, the Company expensed $1.5 million and $1.6 million, respectively, related to performance stock awards.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Common Stock Repurchase Program

Reconciliation of Basic and Diluted Earnings Per Share

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


	Year Ended December 31, 2005
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	36,615	47,711,894	$	0.77

Effect of dilutive securities:
Unvested restricted stock		—	136,579
Stock options		—	459,437

Diluted earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	36,615	48,307,910	$	0.76

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Year Ended December 31, 2004
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	33,369	47,426,813	$	0.70

Effect of dilutive securities:
Unvested restricted stock		—	84,933
Stock options		—	507,975

Diluted earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	33,369	48,019,721	$	0.69


	Year Ended December 31, 2003
	Income		Shares	Per Share
	(In thousands)
Basic earnings per share:
Income before cumulative effect of accounting change and extraordinary item	$	20,322	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 and extraordinary item	$	20,322	48,814,761	$	0.42

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,
	2005		2004		2003
Options excluded		—		178,845		1,029,411
Exercise price range	$	—	$	13.77 -$15.99	$	11.00 - $15.99

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)
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	)
Other comprehensive loss		(74	)		(1,413	)		—			(1,487	)
Income tax benefit		15			532			—			547

Balance at December 31, 2004		6,355			(16,908	)		—			(10,553	)
Other comprehensive loss		(2,359	)		(6,128	)		(22,296	)		(30,783	)
Income tax benefit		472			2,299			8,398			11,169

Balance at December 31, 2005	$	4,468		$	(20,737	)	$	(13,898	)	$	(30,167	)

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

G.	Long-Term Debt and Financing Obligations

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


	December 31,
	2005			2004
	(In thousands)
Long-Term Debt:
First Mortgage Bonds (1):
8.90% Series D, issued 1996, due 2006	$	—		$	175,807
9.40% Series E, issued 1996, due 2011		—			183,555
Pollution Control Bonds (2):
2005 Series B refunding bonds, due 2040		63,500			63,500
4.80% 2005 Series A refunding bonds, due 2040		59,235			59,235
2005 Series C, due 2040		37,100			37,100
4.00% 2002 Series A refunding bonds, due 2032		33,300			33,300
Senior Notes (3):
Senior Notes, net of discount		397,703			—
Promissory note, due 2005 (4)		—			35

Total long-term debt		590,838			552,532
Financing Obligations:
Nuclear fuel ($21,727 due in 2006) (5)		41,907			41,196

Total long-term debt and financing obligations		632,745			593,728
Current Portion (amount due within one year)		(21,727	)		(214,092	)

	$	611,018		$	379,636

(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. At December 31, 2005, the Company had $100 million of Collateral Series First Mortgage Bonds outstanding under the First Mortgage Indenture which secures its credit facility, as discussed below.

In May 2005, the Company commenced a cash tender offer for any and all of its 8.90% Series D First Mortgage Bonds due February 1, 2006 and its 9.40% Series E First Mortgage Bonds due May 1, 2011, which were callable by the Company beginning on February 1, 2006 (collectively the “Bonds”). The total outstanding principal amount of the Bonds subject to the offer was approximately $359.4 million. On June 3, 2005, the Company completed the cash tender offer, and

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

paid approximately $289.9 million for principal, premium and accrued and unpaid interest for all Bonds tendered and accepted for payment. On June 7, 2005, the Company exercised its right to legally defease all Bonds which were not tendered by the expiration date of the tender offer by depositing approximately $95.7 million with a trustee for payment of principal, premium and accrued interest through February 1, 2006. The cash tender offer and legal defeasance of first mortgage bonds was financed through the issuance of Senior Notes (see below). As a result of the cash tender offer and legal defeasance, the Company has concluded that the liabilities associated with the Bonds have been extinguished in accordance with SFAS No. 140, “Accounting for Transfers and Services of Financial Assets and Extinguishments of Liabilities.”

Repurchases of First Mortgage Bonds made during 2004 and 2003 are as follows (in thousands):


	Years Ended December 31,
	2004		2003
8.25% Series C	$	—	$	3,278
8.90% Series D		10,375		—
9.40% Series E		25,629		—

Total	$	36,004	$	3,278

Internally generated funds were used for the repurchases in 2004 and 2003. A loss of $5.4 million was recorded in 2004 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. On August 1, 2005, the Company reissued three series of pollution control bonds in the amounts of $63.5 million, $59.2 million and $37.1 million. The $59.2 million bonds which mature in 2040, were reissued with a fixed interest rate of 4.80% and an effective interest rate of 5.27% after considering related insurance and issuance costs. The $63.5 million and $37.1 million bonds, which also mature in 2040, were reissued with a variable rate that is repriced weekly, 3.60% and 3.25% at December 31, 2005, respectively. The Company also remarketed $33.3 million of pollution control bonds which bear a fixed interest rate of 4% until August 1, 2012 which is the date the bonds are due to be remarketed. The effective interest rate for these bonds is 4.70% after considering related insurance and issuance costs. The interest rate will remain at its current fixed interest rate until remarketing in August 2012. The reissuance and remarketing replaced four series of bonds which were subject to mandatory tender or remarketing as of August 1, 2005.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(3)	Senior Notes

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

In May 2005, the Company issued $400.0 million aggregate principal amount of its 6% Senior Notes due May 15, 2035 (the “Notes”) under its shelf registration statement. The proceeds from the issuance of the Notes of $397.7 million (net of a $2.3 million discount) were used to fund the retirement of the First Mortgage Bonds.

(4)	Promissory Note

The note was paid in full in 2005.

(5)	Nuclear Fuel Financing

The Company has available a $100 million credit facility that was renewed for a five-year term in December 2004. 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 2005. No amounts are currently outstanding on this facility for working capital needs.

Excluding future obligations and maturities related to nuclear fuel purchase commitments, the Company has no scheduled maturities of long-term debt and financing obligations for the next five years as of December 31, 2005.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2005 and 2004 are presented below (in thousands):


	December 31,
	2005			2004
Deferred tax assets:
Alternative minimum tax credit carryforward	$	44,818		$	51,503
Pensions and benefits		56,500			55,248
Benefits of tax loss carryforwards		34,246			682
Asset retirement obligation		23,449			21,136
Investment tax credit carryforward		2,577			5,579
Other		8,585			5,136

Total gross deferred tax assets		170,175			139,284
Less federal valuation allowance		—			2,911

Net deferred tax assets		170,175			136,373

Deferred tax liabilities:
Plant, principally due to depreciation and basis differences		(225,053	)		(202,520	)
Decommissioning		(27,083	)		(25,854	)
Deferred fuel		(30,258	)		(2,494	)
Other		(8,386	)		(10,987	)

Total gross deferred tax liabilities		(290,780	)		(241,855	)

Net accumulated deferred income taxes	$	(120,605	)	$	(105,482	)

The deferred tax asset valuation allowance decreased by approximately $2.9 million in 2005, increased $0.6 million in 2004, and decreased $0.8 million in 2003. The 2005 valuation allowance decrease of $2.9 million is primarily related to expired investment tax credits of $5.7 million less deferred tax benefits of $2.0 million. The 2004 valuation allowance increase of $0.6 million consists of a revaluation of investment tax credits as a result of the IRS settlement. 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 investment tax credits that were utilized in 2003 and (ii) a $0.5 million write-down related to expired investment tax credits of $0.8 million less deferred tax benefits of $0.3 million.

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

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2005			2004			2003
Income tax expense:
Federal:
Current	$	(4,909	)	$	10,542		$	1,873
Deferred		23,046			10,905			30,541

Total federal income tax		18,137			21,447			32,414

State:
Current		(1,788	)		(1,745	)		1,297
Deferred		1,583			(9,499	)		4,553

Total state income tax		(205	)		(11,244	)		5,850

Total income tax expense		17,932			10,203			38,264

Tax benefit (expense) classified as cumulative effect of accounting change		657			—			(25,031	)
Tax expense classified as extraordinary gain on re-application of SFAS No. 71		—			(1,005	)		—

Total income tax expense before cumulative effect of accounting change or extraordinary item	$	18,589		$	9,198		$	13,233

The current federal income tax benefit for 2005 results primarily from a reversal of alternative minimum tax (“AMT”) for prior years as a result of increased tax deductions due to several method changes primarily related to tax depreciation and repair allowances. The current income tax expense for 2004 and 2003 results primarily from the accrual of AMT. The significant increase in 2004 from 2003 primarily relates to a settlement with the IRS of a tax audit of the 1996 to 1998 federal income tax returns which resulted in additional current tax expense and a reduction in deferred tax expense. Deferred federal income tax includes an offsetting AMT expense of $6.7 million for 2005, and an offsetting AMT benefit of $18.9 million and $2.1 million for 2004 and 2003, respectively. The state income tax benefit for 2004 results primarily from the state effects of the re-application of SFAS No. 71 to the Company’s New Mexico jurisdictional operations and the IRS settlement.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2005			2004			2003
Federal income tax expense computed on income at statutory rate	$	18,709		$	15,881		$	34,377
Difference due to:
State taxes, net of federal benefit		(133	)		(2,485	)		3,802
State taxes, net of federal benefit on re-application of SFAS No. 71		—			(4,823	)		—
Other tax regulatory assets and liabilities on re-application of SFAS No. 71		—			4,846			—
Reduction in estimated contingent tax liability		—			(3,520	)		—
Other		(644	)		304			85

Total income tax expense		17,932			10,203			38,264
Tax benefit (expense) classified as cumulative effect of accounting change		657			—			(25,031	)
Tax expense classified as extraordinary gain on re-application of SFAS No. 71		—			(1,005	)		—

Total income tax expense before cumulative effect of accounting change and extraordinary income	$	18,589		$	9,198		$	13,233

Effective income tax rate		33.5	%		22.5	%		39.0	%

Effective income tax rate without IRS settlement		33.5	%		36.2	%		39.0	%

The effective income tax rate without IRS settlement excludes the tax benefit associated with the reduction in estimated contingent tax liability of $3.5 million and state taxes net of federal benefit of $2.7 million recorded in 2004. See Note I.

As of December 31, 2005, the Company had $91.2 million of federal and $42.0 million of state tax net operating loss (“NOL”) carryforwards, $44.8 million of AMT credit carryforwards, $2.3 million of research and development tax credits, and $0.2 million of wind energy credits. If unused, the NOL carryforwards would expire at the end of 2012 through 2025, the state NOL carryforwards would expire at the end of 2010, the research and development tax credits would expire at the end of 2011 through 2018, the wind energy carryforwards would expire at the end of 2016 through 2020, and the AMT credit carryforwards have an unlimited life.

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

I.	Commitments, Contingencies and Uncertainties

Power Contracts

As of December 31, 2005, 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 Energy	25 MW	2006 (excludes April)
Purchase Capacity	133 MW	2006 through 2025

In addition to the above transactions, the Company has also entered into several agreements with various counterparties for the forward firm purchases and sales of electricity during the first quarter of 2006:


Type of Contract	Quantity	Term
Purchase Off-peak Energy	50 MW	1st Quarter 2006
Sale On-peak Energy	25 MW	1st Quarter 2006
Sale Off-peak Energy	175 MW	1st Quarter 2006

Environmental Matters

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Years Ended December 31,
	2005		2004		2003
Clean Air Act	$	1,106	$	762	$	1,060
Clean Water Act (1)		1,708		1,206		649

(1)	Includes $1.0 million and $0.6 million in remediation costs for the twelve months ended December 31, 2005 and 2004, respectively.

Tax Matters

The Company’s federal income tax returns for the years 1999 through 2002 have been examined by the IRS. On May 9, 2005, the Company received the IRS notice of proposed deficiency. The primary audit adjustments proposed by the IRS related to (i) whether the Company was entitled to currently deduct payments related to the repair of the Palo Verde Unit 2 steam generators or whether these payments should be capitalized and depreciated and (ii) whether the Company was entitled to currently

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

deduct payments related to the dry cask storage facilities for spent nuclear fuel or whether these payments should be capitalized and depreciated. The proposed IRS adjustments would affect the timing of these deductions not their ultimate deductibility for federal tax purposes. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s cash flows. The IRS is currently performing an examination of the 2003 and 2004 income tax returns.

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 of the ongoing examination cannot be predicted with certainty, and while the contingent tax liability may not in fact be sufficient, the Company believes that the amount of contingent tax liability recorded as of December 31, 2005 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 sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. As of December 31, 2005, the Company has a reserve for warranty claims in the amount of approximately $1.3 million. Accruals, charges and balances for the reserve for warranty claims are as follows:


	Years Ended December 31,
	2005			2004			2003
Balance at beginning of year	$	1,305		$	1,500		$	1,413
Accrual of warranty costs		—			—			466
Charges for work performed		(17	)		(195	)		(379	)

Balance at end of year	$	1,288		$	1,305		$	1,500

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

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Customer Information System

During 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.

Lease Agreements

The Company has operating leases for administrative offices and certain warehouse facilities. The administrative offices 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 warehouse facilities lease expires in December 2009 and has three concurrent renewal options of one year each. The lease payments are $0.3 million annually. The lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.

The Company’s total annual rental expense related to operating leases was $1.1 million, $1.2 million and $1.9 million for 2005, 2004 and 2003, respectively. As of December 31, 2005, the Company’s minimum future rental payments for the next five years are as follows (in thousands):


2006	$	1,300
2007		300
2008		300
2009		300
2010		—

Union Matters

The collective bargaining agreement with existing union employees expires in June 2006 and the Company anticipates entering into negotiations on a new collective bargaining agreement in the second quarter of 2006. In addition, the Company is presently conducting collective bargaining negotiations with an additional 144 employees from the Company’s meter reading and collections area, facilities services area and customer service area who voted for union representation in 2003 and 2004.

J.	Litigation

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 antitrust laws, as well as for 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. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle has filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. The parties are awaiting a hearing and decision on that appeal. While the Company believes that these matters are without merit, the Company is unable to predict the outcome or range of any possible loss.

100

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases. Wah Chang and the City of Tacoma have both filed notices of appeal with the U.S. Court of Appeals for the Ninth Circuit. The parties have filed briefs in both cases and are awaiting a hearing and decision. While the Company believes that these matters are without merit and intends to defend itself vigorously, the Company is unable to predict the outcome or range of possible loss.

See Note B for discussion of the effects of government legislation and regulation 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 at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, debt securities and cash equivalents and are managed by professional investment managers appointed by the Company.

The Company’s non-qualified retirement income plan for 2003 is a non-funded defined benefit plan which covers certain former employees of the Company. During 2004, the Company adopted a new non-qualified retirement income plan to cover certain active employees of the Company. The benefit cost for the non-qualified retirement income plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.

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 plans under SFAS No. 87, “Employers’ Accounting for Pensions.” 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.

101

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	December 31,
	2005						2004
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Change in benefit obligation:
Benefit obligation at end of prior year	$	165,281		$	21,404		$	150,178		$	19,816
Service cost		5,021			143			4,382			59
Interest cost		9,351			1,281			8,891			1,227
Amendments		—			—			—			1,162
Actuarial loss		6,528			2,324			6,457			796
Benefits paid		(4,990	)		(1,629	)		(4,627	)		(1,656	)

Benefit obligation at end of year		181,191			23,523			165,281			21,404

Change in plan assets:
Fair value of plan assets at end of prior year		105,682			—			87,558			—
Actual return on plan assets		4,500			—			8,751			—
Employer contribution		18,300			1,629			14,000			1,656
Benefits paid		(4,990	)		(1,629	)		(4,627	)		(1,656	)

Fair value of plan assets at end of year		123,492			—			105,682			—

Funded status at end of year		(57,699	)		(23,523	)		(59,599	)		(21,404	)
Unrecognized net actuarial loss		62,433			5,764			54,915			3,731
Unrecognized prior service cost		153			973			176			1,068

Prepaid/(Accrued) benefit cost	$	4,887		$	(16,786	)	$	(4,508	)	$	(16,605	)

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


	December 31,
	2005						2004
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Prepaid benefit cost	$	—		$	—		$	—		$	—
Accrued benefit cost		(24,976	)		(20,976	)		(28,636	)		(20,419	)
Intangible assets		153			153			176			147
Accumulated other comprehensive income		29,710			4,037			23,952			3,667

Net amount recognized	$	4,887		$	(16,786	)	$	(4,508	)	$	(16,605	)

102

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accumulated benefit obligation for all retirement plans was $169.4 million and $154.7 million at December 31, 2005 and 2004, respectively.

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


	December 31,
	2005						2004
	Retirement Income Plan			Non- Qualified Retirement Income Plans			Retirement Income Plan			Non- Qualified Retirement Income Plans
Projected benefit obligation	$	(181,191	)	$	(23,523	)	$	(165,281	)	$	(21,404	)
Accumulated benefit obligation		(148,468	)		(20,976	)		(134,317	)		(20,419	)
Fair value of plan assets		123,492			—			105,682			—

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


	December 31,
	2005				2004
	Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans
Discount rate	5.50	%	5.50	%	5.75	%	5.75	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%	5.00	%

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


	Years Ended December 31,
	2005					2004					2003
	Retirement Income Plan			Non- Qualified Retirement Income Plans		Retirement Income Plan			Non- Qualified Retirement Income Plans		Retirement Income Plan			Non- Qualified Retirement Income Plans
Service cost	$	5,021		$	143	$	4,382		$	59	$	3,812		$	—
Interest cost		9,351			1,281		8,891			1,227		8,403			1,207
Expected return on plan assets		(9,426	)		—		(7,926	)		—		(7,536	)		—
Amortization of:
Net loss		3,938			291		3,329			94		1,720			16
Prior service cost		21			94		21			94		21			—

Net periodic benefit cost	$	8,905		$	1,809	$	8,697		$	1,474	$	6,420		$	1,223

103

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The increase in minimum liability included in other comprehensive income is as follows (in thousands):


	Years Ended December 31,
	2005				2004				2003
	Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans
Increase in minimum liability included in other comprehensive income	$	5,757	$	371	$	775	$	638	$	3,175	$	1,059

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost at January 1:


	2005				2004				2003
	Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans		Retirement Income Plan		Non- Qualified Retirement Income Plans
Discount rate	5.75	%	5.75	%	6.00	%	6.00	%	6.50	%	6.50	%
Expected long-term return on plan assets	8.50	%	N/A		8.50	%	N/A		8.50	%	N/A
Rate of compensation increase	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	N/A

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. The Company changed its discount rate to determine the benefit obligations from 5.75% to 5.50% at December 31, 2005. For determining 2006 benefit costs, the 5.50% discount rate is not expected to change. A 1.0% decrease in the discount rate would increase the 2005 retirement plans’ projected benefit obligation by 16%. A 1.0% increase in the discount rate would decrease the 2005 retirement plans’ projected benefit obligation by 13%.

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.

104

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Given recent market conditions, the Company has emphasized capital preservation and therefore, the asset allocations at December 31, 2005 and 2004 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s Retirement Plan weighted-average asset allocations by asset category are as follows:


	December 31,
	2005		2004
Asset Category:
Equity securities	43	%	45	%
Debt securities	33		32
Cash equivalents	24		23

Total	100	%	100	%

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 contributions for the Retirement Plan, as actuarially calculated, are at least the minimum funding amounts required by the IRS. The Company expects to contribute $13.7 million to its retirement plans in 2006, although the Company has no 2006 minimum funding requirements for the Retirement Plan.

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


	Retirement Income Plan		Non- Qualified Retirement Income Plans
2006	$	5,654	$	1,702
2007		5,906		1,584
2008		6,242		1,563
2009		6,923		1,528
2010		7,740		1,577
2011-2015		53,660		8,375

105

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.” Contributions from the Company are based on the funding amounts established 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 Company elected to defer recognition of the potential effect of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Act”) until authoritative guidance on the accounting for the federal subsidy was issued. In May 2004, the FASB issued FASB Staff Position No. 106-2 “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (“FSP 106-2”) which provided guidance on the accounting for the effects of the Act for employers that sponsor a single-employer defined benefit postretirement healthcare plan for which the employer has concluded that prescription drug benefits available under the plan are actuarially equivalent to the Medicare Part D benefit and the expected subsidy will offset or reduce the employer’s share of the cost of the benefit. The Company determined that the prescription drug benefits of its plan were actuarially equivalent to the Medicare Part D benefit. FSP 106-2 requires measurement of the postretirement benefit obligation, the plan assets, and the net periodic postretirement benefit cost to reflect the effects of the subsidy.

106

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plans shown with and without the recognition of Medicare Part D (in thousands):


	Including December 31,						Excluding December 31,
	2005			2004			2005			2004
Change in benefit obligation:
Benefit obligation at end of prior year	$	114,637		$	118,182		$	132,665		$	113,569
Service cost		4,749			3,796			5,440			4,346
Interest cost		6,667			5,839			7,704			6,736
Amendments		(22,711	)		(2,210	)		(22,711	)		(2,211	)
Actuarial loss (gain)		11,703			(8,490	)		13,434			12,705
Benefits paid		(2,650	)		(2,800	)		(2,650	)		(2,800	)
Retiree contributions		374			320			374			320

Benefit obligation at end of year		112,769			114,637			134,256			132,665

Change in plan assets:
Fair value of plan assets at end of prior year		23,207			20,906			23,207			20,906
Actual return on plan assets		364			1,359			364			1,359
Employer contribution		3,422			3,422			3,422			3,422
Benefits paid		(2,650	)		(2,800	)		(2,650	)		(2,800	)
Retiree contributions		374			320			374			320

Fair value of plan assets at end of year		24,717			23,207			24,717			23,207

Funded status		(88,052	)		(91,430	)		(109,539	)		(109,458	)
Unrecognized net actuarial loss (gain)		7,284			(5,438	)		25,131			10,756
Unrecognized prior service benefit		(24,316	)		(1,959	)		(24,316	)		(1,959	)

Accrued postretirement cost	$	(105,084	)	$	(98,827	)	$	(108,724	)	$	(100,661	)

Amounts recognized in the Company’s consolidated balance sheets consist of accrued postretirement costs of $105.1 million and $98.8 million for 2005 and 2004, respectively.

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


	2005		2004
Discount rate at end of year	5.50	%	5.75	%
Rate of compensation increase	5.00	%	5.00	%
Trend rates:
Initial	9.60	%	9.60	%
Ultimate	6.00	%	6.00	%
Years ultimate reached	4		4

107

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The components of net periodic benefit cost shown including and excluding the Medicare Part D subsidy are presented below (in thousands):


	Including Years Ended December 31,
	2005			2004			2003
Service cost	$	4,749		$	3,796		$	3,915
Interest cost		6,667			5,839			6,468
Expected return on plan assets		(1,382	)		(1,258	)		(1,020	)
Amortization of:
Prior service cost		(355	)		(251	)		—
Net gain		—			(387	)		—

Net periodic benefit cost	$	9,679		$	7,739		$	9,363


	Excluding Years Ended December 31,
	2005			2004			2003
Service cost	$	5,440		$	4,346		$	3,915
Interest cost		7,704			6,736			6,468
Expected return on plan assets		(1,382	)		(1,258	)		(1,020	)
Amortization of:
Prior service cost		(355	)		(251	)		—
Net loss		78			—			—

Net periodic benefit cost	$	11,485		$	9,573		$	9,363

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost: (These assumptions are the same including and excluding Medicare Part D)


	2005		2004		2003
Discount rate at beginning of year	5.75	%	6.00	%	6.50	%
Expected long-term return on plan assets	5.90	%	5.90	%	5.90	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. At December 31, 2005, the Company changed its discount rate from 5.75% to 5.50% for the other postretirement benefits plan. For determining 2006 benefit cost, the 5.50% discount rate is not expected to change. A 1.0% decrease in the discount rate would increase the 2005 accumulated

108

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

postretirement benefit obligation by 18.1%. A 1.0% increase in the discount rate would decrease the 2005 accumulated postretirement benefit obligation by 14.2%.

For measurement purposes, a 9.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006; the rate was assumed to decrease gradually to 6% for 2009 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the benefit obligation by $18.6 million or $15.0 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of the net periodic benefit cost by $2.1 million or $1.6 million, respectively.

The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.90%. 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, 2005 and 2004 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s other postretirement benefits plan weighted average asset allocations by asset category are as follows:


	December 31,
	2005		2004
Asset Category:
Equity securities	59	%	54	%
Debt securities	35		30
Cash equivalents	6		16

Total	100	%	100	%

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 2006.

109

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Including Medicare Part D Subsidy		Excluding Medicare Part D Subsidy		Reduction due to the Medicare Part D Subsidy
2006	$	2,733	$	2,994	$	(261	)
2007		3,202		3,502		(300	)
2008		3,621		3,964		(343	)
2009		4,100		4,488		(388	)
2010		4,795		5,219		(424	)
2011-2015		33,273		36,313		(3,040	)

401(k) Defined Contribution Plans

The Company sponsors 401(k) defined contribution plans covering substantially all employees. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s base salary subject to certain other limits. Total matching contributions made to the savings plans for the years 2005, 2004 and 2003 were $1.5 million, $1.3 million and $1.3 million, respectively.

Annual Short-Term Bonus Plan

The Annual Short-Term Bonus Plan (the “Bonus Plan”) provided for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards was based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors Compensation Committee. Generally, these performance measures were based on meeting certain financial, operational and individual performance criteria. For 2005, the financial performance goals were based on earnings per share and the operational performance goals were based on safety and customer satisfaction. If a certain level of earnings per share was not attained, no bonuses would have been paid under the Bonus Plan. The Company was able to attain the required levels of improvements in the earnings per share and the safety goals for low risk employees which resulted in a 2005 bonus of $2.5 million. In 2004 the Company was able to attain the required levels of improvement in earnings per share and the customer satisfaction goals which resulted in a bonus of $3.5 million. The Company was also able to attain the required levels of improvement in the safety performance measures for medium and high risk employees in 2005, 2004 and 2003, which resulted in safety bonuses of $1.0 million, $0.9 million and $0.7 million, respectively. The Company has renewed the Bonus Plan in 2006 with similar goals.

110

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

L.	Franchises and Significant Customers

City of El Paso Franchise

Las Cruces Franchise

Military Installations

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

111

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

customer deposits approximate fair value because of the short maturity of these items. Decommissioning trust funds are carried at market value.

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


	December 31,
	2005				2004
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
First Mortgage Bonds	$	—	$	—	$	359,362	$	386,947
Pollution Control Bonds		193,135		193,399		193,135		197,871
Senior Notes		397,703		397,957		—		—
Nuclear Fuel Financing (1)		41,907		41,907		41,196		41,196

Total	$	632,745	$	633,263	$	593,693	$	626,014

(1)	The interest rate on the Company’s financing for nuclear fuel purchases is reset every quarter to reflect current market rates. Consequently, the carrying value approximates fair value.

Treasury Rate Locks. During the first quarter of 2005, the Company entered into treasury rate lock agreements to hedge against potential movements in the treasury reference interest rate pending the issuance of the Notes. These treasury rate locks were terminated on May 11, 2005. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge of approximately $14.0 million, net of tax, as a component of accumulated other comprehensive loss. In May 2005, the Company began to recognize in earnings (as additional interest expense) the accumulated other comprehensive loss associated with the cash flow hedge. During the next twelve month period, approximately $0.3 million of this accumulated other comprehensive loss item will be reclassified to interest expense.

Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts, 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.

112

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2005, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.

Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $96.0 million at December 31, 2005. Gross unrealized losses on marketable securities and the fair value of the related securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2005, were as follows (in thousands):


	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	$	15,151	$	(309	)	$	1,301	$	(57	)	$	16,452	$	(366	)
Federal Agency Mortgage Backed Securities		650		(13	)		1,812		(78	)		2,462		(91	)
Municipal Obligations		5,213		(79	)		1,130		(68	)		6,343		(147	)
Corporate Obligations		4,145		(33	)		2,098		(85	)		6,243		(118	)

Total debt securities		25,159		(434	)		6,341		(288	)		31,500		(722	)
Common stock		26,789		(2,084	)		840		(496	)		27,629		(2,580	)

Total temporarily impaired securities	$	51,948	$	(2,518	)	$	7,181	$	(784	)	$	59,129	$	(3,302	)

The total impaired securities are comprised of approximately 130 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 considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these investments until their market price recovers, these investments are not considered other-than-temporarily impaired. The Company will not have a requirement to expend monies held in trust before 2024 or a later period when the Company begins to decommission Palo Verde. For 2005 the Company realized a $0.1 million gain on the sale of investments that were previously considered impaired. During the years ended December 31, 2004 and 2003, the Company recognized other than temporary impairment losses of marketable securities of $0.3 million and $0.6 million, respectively.

113

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

N.	Supplemental Statements of Cash Flows Disclosures


	Years Ended December 31,
	2005		2004		2003
	(In thousands)
Cash paid for:
Interest on long-term debt and financing obligations	$	48,407	$	49,392	$	51,596
Income taxes		1,195		9,385		17,660
Other interest		—		5		12
Non-cash investing and financing activities:
Grants of restricted shares of common stock		1,975		812		724
Change in federal and state deferred tax valuation allowance credited to capital in excess of stated value (1)		—		3,380		295
Plant in service acquired through incurring obligations subject to a service agreement		—		—		8,139

(1)	See Note H.

114

Index to Financial Statements

EL PASO ELECTRIC COMPANY AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

O.	Selected Quarterly Financial Data (Unaudited)


	2005 Quarters										2004 Quarters
	4th			3rd		2nd			1st		4th			3rd		2nd		1st
						(In thousands except for share data)
Operating revenues (1)	$	213,397		$	242,031	$	189,300		$	159,185	$	165,629		$	204,941	$	182,206	$	155,852
Operating income		15,611			51,278		22,333			18,661		7,579			40,582		26,338		18,572
Income (loss) before cumulative effect of accounting change and extraordinary item		7,808			28,012		(3,962	)		4,757		(1,182	)		23,938		7,699		2,914
Cumulative effect of accounting change, net of tax		(1,093	)		—		—			—		—			—		—		—
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—		—			—		—			1,802		—		—
Net income (loss)		6,715			28,012		(3,962	)		4,757		(1,182	)		25,740		7,699		2,914
Basic earnings per share:
Income (loss) before cumulative effect of accounting change and extraordinary item		0.16			0.59		(0.08	)		0.10		(0.02	)		0.50		0.16		0.06
Cumulative effect of accounting change, net of tax		(0.02	)		—		—			—		—			—		—		—
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—		—			—		—			0.04		—		—
Net income (loss)		0.14			0.59		(0.08	)		0.10		(0.02	)		0.54		0.16		0.06
Diluted earnings per share:
Income (loss) before cumulative effect of accounting change and extraordinary item		0.16			0.58		(0.08	)		0.10		(0.02	)		0.50		0.16		0.06
Cumulative effect of accounting change, net of tax		(0.02	)		—		—			—		—			—		—		—
Extraordinary gain on re-application of SFAS No. 71, net of tax		—			—		—			—		—			0.04		—		—
Net income (loss)		0.14			0.58		(0.08	)		0.10		(0.02	)		0.54		0.16		0.06

(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.

115

Index to Financial Statements

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.

Controls and Procedures

Evaluation of disclosure controls and procedures. During the period covered by this report, 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, 2005, (the “Evaluation Date”), concluded that as of the Evaluation Date, our 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 us and our consolidated subsidiary would be made known to them by others within those entities.

Management’s Annual Report on Internal Control Over Financial Reporting. Included herein under the caption “Management Report on Internal Control Over Financial Reporting” on page 49 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2005, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

None.

116

Index to Financial Statements

PART III

Item 10.

Directors and Executive Officers of the Registrant

Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2006 Annual Meeting of Shareholders (the “2006 Proxy Statement”) under the heading “Nominee and Directors of the Company.” Information regarding our executive officers, included herein under the caption “Executive Officers of the Registrant” in Part I, Item 1 above, is incorporated herein by reference.

The information concerning the identification of our standing audit committee required by this Item is incorporated by reference from the 2006 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters,” and under the heading “Audit Committee Report.”

The information concerning our audit committee financial experts required by this Item is incorporated by reference from the 2006 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters.”

The information concerning compliance with Section 16(a) of the Exchange Act required by this Item is incorporated by reference from the 2006 Proxy Statement under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” under the heading “Security Ownership of Certain Beneficial Owners and Management.”

We have adopted a Code of Ethics that is incorporated by reference from the 2006 Proxy Statement under the caption “Corporate Governance Matters” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters.”

Item 11.

Executive Compensation

Incorporated herein by reference from the 2006 Proxy Statement under the caption “Executive Compensation” under the heading “Certain Additional Information.”

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Incorporated herein by reference from the 2006 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”

117

Index to Financial Statements

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	1,354,448	$	11.12	353,104
Equity compensation plans not approved by security holders	—		—	—

Total	1,354,448	$	11.12	353,104

Item 13.

Certain Relationships and Related Transactions

Incorporated herein by reference from the 2006 Proxy Statement under the heading “Certain Business Transactions.”

Item 14.

Principal Accounting Fees and Services

Incorporated herein by reference from the 2006 Proxy Statement under the heading “Independent Auditors.”

PART IV

Item 15.

Exhibits and Financial Statement Schedules

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


		Page
1.	Financial Statements:

	See Index to Financial Statements	50

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.

118

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

Exhibit 3 – Articles of Incorporation and Bylaws:

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

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

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

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

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

4.01-02		– Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01.

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

4.02		– Reserved

4.03		– Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank of California, N.A. as Trustee dated as of July 1, 2005 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2005 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.30 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.04		– Loan Agreement dated July 1, 2005 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.31 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

119

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

4.05		– Representation and Indemnity Agreement dated July 27, 2005 among El Paso Electric Company, Citigroup Global Markets Inc., BNY Capital Markets, Inc., J.P. Morgan Securities Inc., and the Maricopa County, Arizona Pollution Control Corporation, relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.32 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

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

4.07		– Loan Agreement dated July 1, 2005 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.06. (Exhibit 4.34 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.08		– Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank of California, N.A. as Trustee dated as of July 1, 2005 relating to $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2005 Series C (El Paso Electric Company Palo Verde Project). (Exhibit 4.35 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.09		– Loan Agreement dated July 1, 2005 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.08. (Exhibit 4.35 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.10		– Remarketing Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibits 4.03, 4.06 and 4.08. (Exhibit 4.37 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.11		– Tender Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibits 4.03, 4.06 and 4.08. (Exhibit 4.38 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

120

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

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

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

4.14		– Representation and Indemnity Agreement dated July 27, 2005 among El Paso Electric Company, Citigroup Global Markets Inc., BNY Capital Markets, Inc., J.P. Morgan Securities Inc., and the Maricopa County, Arizona Pollution Control Corporation, relating to the Pollution Control Bonds referred to in Exhibits 4.06 and 4.08. (Exhibit 4.41 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.15		– Remarketing and Purchase Agreement dated July 27, 2005 among El Paso Electric Company and Citigroup Global Markets Inc., as remarketing agent, and Citigroup Global Markets Inc., BNY Capital Markets, Inc., and J.P. Morgan Securities Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. (Exhibit 4.42 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.16		– Tender Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. (Exhibit 4.43 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

4.17		– Remarketing Agreement dated August 1, 2005 between El Paso Electric Company and Citigroup Global Markets Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. (Exhibit 4.44 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

121

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

4.18		– Ordinance No. 2002-1134 adopted by the City Council of Farmington, New Mexico on July 9, 2002 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 principal amount of its Pollution Control Revenue Refunding Bonds, 2002 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.22 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002)

Exhibit 10 – Material Contracts:

10.01		– Co-Tenancy Agreement, dated July 19, 1966, and Amendments No. 1 through 5 thereto, between the Participants of the Four Corners Project, defining the respective ownerships, rights and obligations of the Parties. (Exhibit 10.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.01-01		– Amendment No. 6, dated February 3, 2000, to Exhibit 10.01. (Exhibit 10.01-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

10.02		– Supplemental and Additional Indenture of Lease, dated May 27, 1966, including amendments and supplements to original Lease Four Corners Units 1, 2 and 3, between the Navajo Tribe of Indians and Arizona Public Service Company, and including new Lease Four Corners Units 4 and 5, between the Navajo Tribe of Indians and Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company. (Exhibit 4-e to Registration Statement No. 2-28692 on Form S-9)

10.02-01		– Amendment and Supplement No. 1, dated March 21, 1985, to Exhibit 10.02. (Exhibit 19.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1985)

10.03		– El Paso Electric Company 1996 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-17971 on Form S-8)

10.04		– Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.04-01		– Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)

122

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

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

10.05		– Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.05-01		– Amendment No. 14, dated June 20, 2000, to Exhibit 10.05. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

10.06		– ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.07		– Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)

10.07-01		– Amendment No. 1, dated November 20, 1986, to Exhibit 10.07. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)

10.08		– Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)

10.09		– Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

123

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

10.10		– Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.11		– Reserved

10.12		– Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)

10.13		– Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.13-01		– Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.16. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)

10.14		– Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)

10.15		– Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)

10.16		– Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)

10.17		– Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

124

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

10.18		– 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)

10.19		– Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.20		– Purchase Contract, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)

10.21		– Form of Stock Option Agreement, dated as of June 11, 1996, between the Company and Gary R. Hedrick and J. Frank Bates; officers of the Company. (Exhibit 99.07 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)

10.22		– Decommissioning Trust Agreement, dated as of December 18, 2003, between the Company and Bank of America, N.A., as Decommissioning Trustee for Palo Verde Unit 1.

10.23		– Decommissioning Trust Agreement, dated as of December 18, 2003, between the Company and Bank of America, N.A., as Decommissioning Trustee for Palo Verde Unit 2.

10.24		– Decommissioning Trust Agreement, dated as of December 18, 2003, between the Company and Bank of America, N.A., as Decommissioning Trustee for Palo Verde Unit 3.

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

†10.26		– Amended and Restated Change in Control Agreement between the Company and certain key officers of the Company. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 2005)

††10.27		– 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)

†††10.28		– Form of Stock Option Agreement between the Company and certain key officers of the Company. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)

125

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

††††10.29		– Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)

†††††10.30		– Form of Directors’ Stock Option Agreement between the Company and certain directors of the Company. (Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)

10.31		– El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)

10.32		– Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)

10.33		– Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)

10.34		– Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)

10.35		– Shiprock – Four Corners Project 345 kV Switchyard Interconnection Agreement, dated March 6, 2002. APS Contract No. 51999. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002)

10.36		– Interconnection Agreement dated as of May 23, 2002, between the Company and the Public Service Company of New Mexico. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)

10.36-01		– First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.36. (Exhibit 10.52.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003)

10.37		– Reserved

10.38		– Credit Agreement dated as of December 17, 2004, among the Company, JPMorgan Chase Bank as Trustee, the lenders party hereto and JPMorgan Chase Bank as Administrative Agent, Collateral Agent and Issuing Bank.

10.39		– Eight Treasury Rate Lock agreements between the Company and Credit Suisse First Boston International. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)

126

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

††††††10.40		– Master Power Purchase and Sale Agreement and Transaction Agreement, dated as of July 7, 2004, between the Company and Southwestern Public Service Company. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)

10.41		– Rate Agreement between the Company and the City of El Paso, Texas, dated as of July 1, 2005.

*10.42		– Power Purchase and Sale Agreement, dated as of December 16, 2005, between the Company and Phelps Dodge Energy Services, LLC.

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 133 of this report)

Exhibit 24 – Power of Attorney:

*24.01		– Power of Attorney (set forth on page 132 of the Original Form 10-K)

*24.02		– Certified copy of resolution authorizing signatures pursuant to power of attorney

Exhibit 31 and 32 – Certifications:

*31.01		– Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32.01		– Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Exhibit 99 – Additional Exhibits:

99.01		– Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to Registration Statement No. 33-99744 on Form S-1)

99.02		– 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)

127

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

99.05		– Final Order, entered January 8, 2002, by the New Mexico Public Utility Commission. (Exhibit 99.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)

99.06		– News Release, dated as of December 5, 2002, by the El Paso Electric Company announcing settlement with the FERC Trial Staff. (Exhibit 99.01 to the Company’s Form 8-K, dated as of December 6, 2002)

99.07		– “Stipulated Facts and Remedies,” dated as of December 5, 2002, to be filed by the FERC Trial Staff as part of its written testimony. (Exhibit 99.02 to the Company’s Form 8-K, dated as of December 6, 2002)

*	Filed herewith.

†

Eleven agreements, dated March 10, 2005, substantially identical in all material respects to this exhibit, have been entered into with Gary R. Hedrick; J. Frank Bates; Scott D. Wilson; Steven P. Busser; Fernando Gireud; Kerry B. Lore; Robert C. McNiel; Hector Puente; Guillermo Silva, Jr.; John A. Whitacre; and Helen Williams Knopp; officers of the Company.

One agreement, dated July 11, 2005, substantially identical in all material respects to this exhibit, has been entered into with Andy Ramirez, officer of the Company.

One agreement, dated August 10, 2005, substantially identical in all material respects to this exhibit, has been entered into with David G. Carpenter, officer of the Company.

††

Eight 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.

One agreement, dated as of November 8, 2001, identical in all material respects to this exhibit, has been entered into with Gary R. Hedrick; officer 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 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.

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INDEX TO EXHIBITS


Exhibit Number		Title

		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.

†††		Two agreements, dated January 3, 1998, identical in all material respects to this exhibit, have been entered into with J. Frank Bates and Gary R. Hedrick; officers of the Company.

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

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

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

		One agreement, dated as of November 5, 2001, identical in all material respects to this exhibit, has been entered into with Gary R. Hedrick; officer of the Company.

		One agreement, dated as of November 26, 2001, identical in all material respects to this exhibit, has been entered into with J. Frank Bates; officer of the Company.

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

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

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

††††		In lieu of non-employee director cash compensation, three agreements, dated as of January 2, 2004; and April 1, 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.

		Eleven agreements, dated as of May 5, 2004, 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. Yamarone; and J. Robert Brown; directors of the Company.

129

Index to Financial Statements

INDEX TO EXHIBITS


Exhibit Number		Title

		In lieu of non-employee director cash compensation, four agreements, dated as of July 1, 2004 and October 1, 2004, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz and Patricia Z. Holland-Branch; directors of the Company.

		In lieu of non-employee director cash compensation, four agreements, dated as of January 3, 2005 and April 1, 2005, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz and Patricia Z. Holland-Branch directors of the Company.

		In lieu of non-employee director cash compensation, eleven agreements, dated as of May 4, 2005, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.

		In lieu of non-employee director cash compensation, four agreements, dated as of July 1, 2005 and October 1, 2005, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.

†††††		Eight agreements, dated as of May 8, 1997, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.

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

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

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

††††††		Confidential treatment has been requested and received for the redacted portions of Exhibit 10.03. The copy filed herewith omits the information subject to the confidentiality request. Omissions are designated as “****.” A complete version of this Exhibit has been filed separately with the Securities and Exchange Commission.

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Index to Financial Statements

UNDERTAKING

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

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Index to Financial Statements

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, Scott D. Wilson, J. Frank Bates and Gary D. Sanders, its, his or her true and lawful attorneys-in-fact and agents, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 10th day of March 2006.


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 10, 2006

/s/ SCOTT D. WILSON (Scott D. Wilson)	Senior Vice President and Chief Financial Officer (Principal Financial Officer )	March 10, 2006

/s/ DAVID G. CARPENTER (David G. Carpenter)	Vice President, Corporate Planning and Controller	March 10, 2006

/s/ J. ROBERT BROWN (J. Robert Brown)	Director	March 10, 2006

/s/ JAMES W. CICCONI (James W. Cicconi)	Director	March 10, 2006

/s/ GEORGE W. EDWARDS, JR. (George W. Edwards, Jr.)	Director	March 10, 2006

/s/ RAMIRO GUZMAN (Ramiro Guzman)	Director	March 10, 2006

/s/ JAMES W. HARRIS (James W. Harris)	Director	March 10, 2006

/s/ KENNETH R. HEITZ (Kenneth R. Heitz)	Director	March 10, 2006

/s/ PATRICIA Z. HOLLAND-BRANCH (Patricia Z. Holland-Branch)	Director	March 10, 2006

/s/ MICHAEL K. PARKS (Michael K. Parks)	Director	March 10, 2006

/s/ ERIC B. SIEGEL (Eric B. Siegel)	Director	March 10, 2006

/s/ STEPHEN N. WERTHEIMER (Stephen N. Wertheimer)	Director	March 10, 2006

/s/ CHARLES A. YAMARONE (Charles A. Yamarone)	Director	March 10, 2006

132