CAP ROCK ENERGY CORP - 10-K Annual Report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

ý Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

COMMISSION FILE NUMBER
0-32667

CAP ROCK ENERGY CORPORATION

Texas		75-2794300
(State of Incorporation)		(I.R.S. Employer Identification No.)

500 West Wall Street, Suite 400 Midland, Texas		79701
(Address of principal executive office)		(Zip Code)

Registrant’s telephone number, including area code 915-683-5422

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class		Name of each exchange on which registered
COMMON STOCK, PAR VALUE $.01 PER SHARE		AMERICAN STOCK EXCHANGE

Securities registered pursuant to Section 12(b) of the Act: NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes

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.

Yes

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

Yes

THE AGGREGATE MARKET VALUE OF THE COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT AS OF JUNE 28, 2002, WAS APPROXIMATELY $15,042,200 BASED ON THE CLOSING PRICE OF $11.55 FOR THE COMMON STOCK ON THE AMERICAN STOCK EXCHANGE AS REPORTED BY THE WALL STREET JOURNAL.

THE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING ON MARCH 25, 2003, WAS 1,302,355.
DOCUMENTS INCORPORATED BY REFERENCE

None

PART I

ITEM 1. BUSINESS

The Company

Cap Rock Energy Corporation, its subsidiaries and affiliates (the “Company”) own and operate an electric distribution and transmission business in various non-contiguous areas in the State of Texas. The Company primarily provides electric distribution service to over 35,000 meters in 28 counties in Texas. This includes 23,000 meters in 17 counties in the Midland-Odessa area of West Texas (the “West Texas Division”), 6,100 meters in the Central Texas area around Brady, Texas, and over 4,200 meters in Northeast Texas in Hunt, Collin and Fannin Counties. The Company also provides management services to the Farmersville Municipal Electric System which services nearly 1,700 meters in Farmersville, Texas. The Company’s predecessor in interest, Cap Rock Electric Cooperative, Inc. (the “Cooperative”), was incorporated as an electric cooperative in the State of Texas in 1939.

The Company was formed in December 1998 in accordance with a conversion plan adopted by the members of the Company’s predecessor, the Cooperative, which provided a method for changing the corporate structure from a member owned cooperative to a shareholder owned corporation. The conversion plan provided for the transfer of all of the Cooperative’s assets and liabilities to the Company. It also provided for the payment of the equity accounts and membership interests, if any, of members of the Cooperative through cash, credit on their electric bill or stock in the Company, at the member’s option. The Company operated as a wholly owned subsidiary of the Cooperative until the conversion plan was implemented. Other than the Certificate of Convenience and Necessity (“CCN”), all of the Cooperative’s assets were transferred to the Company in accordance with the conversion plan and the Company assumed all of the Cooperative’s liabilities in early 2002. On February 8, 2002, the Company issued stock to all former members of the Cooperative who chose stock as the method of payment for their equity and membership interest, if any, in the Cooperative. All former members who chose the cash payment option were paid in late 2001. The former members who chose credits on their electric bill are still receiving those credits, with such credits expected to be fully applied by the end of 2003.

An application has been filed with the Public Utility Commission of Texas (“PUCT”) to transfer the Cooperative’s CCN to the Company. The CCN allows its holder to serve customers in specified geographical territories. When the CCN is transferred, the Cooperative will be dissolved and the Company will provide services directly to its retail customers. While the Company’s corporate structure changed from a member owned electric cooperative to a shareholder owned utility in 2002, it is still currently subject to regulation by the PUCT in the category of a cooperative, although that status has been challenged in proceedings currently pending before the PUCT, and is the subject of a proposed bill in the Texas legislature. See “Business - State and Federal Regulation.”

The Company purchases power for resale to its retail customers from wholesale suppliers and distributes that power to its customers over its transmission lines covering over 320 miles and then over 11,000 miles of distribution lines. The Company’s transmission systems interconnect with the systems of power suppliers and other utilities, to permit bulk power transactions with other electricity suppliers. One of the Company’s wholly-owned subsidiaries, NewCorp Resources Electric Cooperative, Inc. (“NewCorp”), owns and operates 305 miles of transmission line which are in the Southwest Power Pool (“SPP”). This transmission system is subject to regulation by the Federal Energy Regulatory Commission (“FERC”). NewCorp provides transmission services to the Company pursuant to a FERC regulated tariff. The Company also owns 18 miles of transmission line located in McCulloch County, Texas, and which are in the Electric Reliability Council of Texas (“ERCOT”). This small transmission line is currently leased to a power provider, Lower Colorado River Authority (“LCRA”). The Company owns approximately 9,800 miles of overhead distribution lines and approximately 1,900 miles of underground distribution lines. The Company believes it has all the franchises and licenses necessary to distribute electricity within the territories where its distribution systems are located and from which substantially all of its gross operating revenue is derived.

The Company’s primary focus is on distribution of electricity to its customers. The Company has not and does not plan to engage in the generation of electricity. In 2002, the Company purchased all electric power pursuant to wholesale electric power contracts with Southwestern Public Service Company (“SPS”), Dynegy Power Marketing, Inc. (“Dynegy”), Lower Colorado River Authority and Garland Power and Light (“Garland”), which accounted for approximately 71.4%, 7.6%, 12.9% and 8.1%, respectively, of the electric power purchases of the Company. Generally, the wholesale electric power supply contracts are based on fixed charges for kWh usage, transportation and auxiliary services and a variable charge for fuel based on kWh usage. The Company’s purchased power costs fluctuate primarily with the price of natural gas. The contracts with SPS, LCRA and Garland expire in 2013, 2016 and 2004, respectively. The Company negotiated a new contract with Garland in 2002 which replaced the Dynegy contract and a previous contract with Texas-New Mexico Power Company. We cannot predict what effect, if any, renegotiation of future expiring contracts may have on the Company’s financial condition and results of operations. However, all costs associated with purchased power are passed through to the retail customer.

Non-Electric Utility Business

The Company has investments in the real estate business, the oil and gas business and the petroleum distribution business, none of which separately or collectively account for 10% or more of the Company’s revenues. See Notes 9 and 11 to consolidated financial statements.

In the past, the Company invested in the oil and gas exploration and production business. The Company no longer makes investments in oil and gas production and exploration. However, the Company has continued to invest in hydrocarbons through its ownership of a company formed to acquire oil and gas mineral and royalty interests. In December 2000, the Company merged its mineral and royalty company with a company with similar goals. The merged company, Map Resources, Inc. (“MAP”), owns oil and gas minerals and royalties and some non-operated working interests. MAP’s primary focus in the future is the acquisition and continuing development of mineral and royalty interests. The Company owns approximately 42% of the common stock of MAP, which does not represent a significant portion of the Company’s business.

The Company has provided a loan to United Fuel and Energy Company (“United Fuel”) which is engaged in the petroleum distribution business. At loan closing, the Company acquired a 10% interest in United Fuel with a right to acquire an additional 10% interest under certain circumstances. In January 2001, the Company acquired a net 5% additional interest in United Fuel from certain selling shareholders of United Fuel, giving the Company a 15% interest in the petroleum distribution company. Under certain conditions, the Company has a right to acquire up to 25% in total of United Fuel. See Note 9 to the consolidated financial statements included herein.

The Company’s real estate investments consist primarily of building and land related to the electric business. The Company is also an investor in certain limited partnerships which own and operate interests in real properties. See “Item 2. Properties” for additional information.

For additional information with respect to the Company’s business segments, see Note 28 to the consolidated financial statements.

Seasonal Nature of Business

The Company’s operating revenues come from electric or electric related sales. Annual sales to the Company’s commercial and industrial, residential and irrigation customers have historically accounted for approximately 50%, 40%, and 10%, respectively, of total electric sales.

Commercial and industrial revenues, derived primarily from electric powered oilfield equipment, are generally not subject to seasonal fluctuation, or normal oil price fluctuations. This is because many producers have pre-committed their output. Electric power requirements can, however, be affected by a dramatic change in the price of oil, which affects the overall market for oil.

Residential sales vary with temperature fluctuations, primarily during the summer months, as the Company’s residential customers use more electric power for cooling during the hot summer months. Historically, approximately 33% of the Company’s annual residential sales occur during the three month period ending September 30.

Irrigation revenues, derived primarily from cotton farmers with electric powered irrigation equipment, are subject to temperature and rainfall fluctuations during the cotton planting and growing seasons. Historically, approximately 70% of the Company’s annual irrigation sales occur during the six month period ending September 30.

Single Customer Reliance

During the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, the Company had no single customer that accounted for more than 10% of its electric revenues.

Employees

As of December 31, 2002, the Company had 116 full-time and two part-time employees, exclusive of temporary employees and contractors. None of the employees are members of any labor unions as of December 31, 2002.

State and Federal Regulation

State Regulation

In 1999, the Texas legislature passed, and the Governor signed, legislation that provided for the restructuring of the electric utility industry in the State of Texas. The legislature found the production and sale of electricity is not a monopoly warranting regulation of rates, operations and services. Competitive electric markets require that, except for transmission and distribution services and for recovery of stranded costs, electric services and the associated prices should be determined by customer choice and the normal forces of competition.

The purpose of customer choice is to create a competitive retail market by allowing each retail customer to choose their provider of electricity and by encouraging full and fair competition to recover excess costs over market of those assets and purchased power contracts. Municipally owned utilities and electric cooperatives are treated differently from other utilities under the state statute providing for customer choice. The statute has separate, specific provisions applicable to investor owned electric utilities, which were required to have customer choice in their service areas beginning January 1, 2002, and municipally owned utilities and electric cooperatives, which are able to choose whether or not to opt into retail competition. These provisions individually govern the transition to and establishment of a fully competitive electric power industry for investor owned utilities, electric cooperatives and municipally owned utilities. Customer choice is only for the provision of electricity and not for distribution or transmission services.

On or before September 1, 2000, each investor owned electric utility was required to separate its regulated utility activities from its customer energy services business activities. By January 1, 2002, each investor owned electric utility operating in the State of Texas was required to separate its business activities into a power generation company, a retail electric provider and/or a transmission and distribution utility. The Company is a transmission and distribution utility. Each investor owned electric utility was also required to submit a plan segregating businesses, which was subject to review by the PUCT. After January 1, 2002, a transmission and distribution company may not sell electricity or otherwise participate in the market for electricity except for the purpose of buying electricity to serve its own customers.

Commencing January 1, 2002, through January 1, 2007, any affiliated retail electric provider was required to make available to residential and small commercial customers of its affiliated transmission and distribution utility, rates, that, on a bundled basis, are six percent less than the affiliated electric utility’s corresponding average residential and small commercial rates that were in effect on January 1, 1999, which is the so-called “price to beat.” Once customer choice was introduced, these utilities could not change rates for residential and small commercial customers that were different from the “price to beat” until the earlier of 36 months or until 40% or more of the electric power consumed within the affiliated transmission and distribution utility’s certificated service area before the onset of customer choice is committed to be served by nonaffiliated retail electric providers. A similar restriction was set for rate changes for small commercial customers.

The effect of the statute was to freeze all investor owned electric utility rates that were in effect on September 1, 1999, until January 1, 2002, and, upon completion of the phase in of customer choice, to lower rates to residential customers and small commercial customers by another six percent. If the “price to beat” jeopardized the financial integrity of the retail electric provider, the PUCT was required to set a price that would maintain the financial integrity of the retail electric provider, but in no event more than the level of rates, on a bundled basis, charged by the affiliated electric utility on September 1, 1999, adjusted for fuel. For the year ended December 31, 2002, approximately 66% of the Company’s revenues were derived from residential customers and small commercial customers with the remaining 34% attributable to irrigation and large commercial customers.

Electric cooperatives were not required to participate in deregulated markets. Under the separate provision in the statute pertaining to electric cooperatives, the board of directors of a cooperative has the discretion to decide if and when the electric cooperative will provide customer choice. Electric cooperatives were not required to functionally unbundle their operating and business activities as investor owned utilities were required to do. If an electric cooperative elects to participate in customer choice, all retail customers within the certificated service area of the cooperative shall have the right of customer choice. An electric cooperative that does not elect to participate in the deregulated market, however, is prohibited from selling electric energy at unregulated prices directly to retail customers outside its certificated retail service area.

The definition of electric cooperative under the state statute includes a provision that allows the Company to be treated like an electric cooperative, and therefore be able to elect whether to participate in retail competition, and, if so, whether to unbundle its operations. Specifically, the definition of “electric cooperative” includes “a successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the members of the electric cooperative, regardless of whether the successor later purchases, acquires, merges with or consolidates with, other electric cooperatives.” Management believes that the Company qualifies for treatment as an electric cooperative under this provision and that it is the only investor owned utility that does qualify for such treatment. A small group of interveners are currently challenging the Company’s right to be treated as a cooperative under the Public Utility Regulatory Act. This challenge is being made before the PUCT proceeding in which the Company and the Cooperative have requested that the Cooperative’s Certificate of Convenience and Necessity be transferred to the Company. See “Legal Proceedings.” If the Company prevails, even as a shareholder owned utility, the Company has and will continue to have all rights and privileges associated with being an electric cooperative because it falls within the definition of electric cooperative established by the statute. Consequently, the Company will have more options available to it than cooperatives and other shareholder owned utilities, because it allows the Company to continue to compete in the market while allowing it the time it needs to become more prepared for entering the deregulated market.

Senate Bill 1280 (“SB 1280”) is proposed legislation in the Texas Legislature which, if passed, would amend the Public Utility Regulatory Act, to treat a successor to an electric cooperative as an investor owned utility. SB 1280 also provides for establishment by the PUCT of schedules and procedures in order to comply with the requirements of deregulation for those successors which were not previously subject to regulation as an investor owned utility prior to September 1, 2003. Although the bill has passed in committee, it must pass in both the Texas Senate and Texas House of Representatives before it becomes law.

Currently the Cooperative’s Board of Directors, not the PUCT, approves all rates and tariffs that the Cooperative charges its members. The Company’s Board of Directors has approved the rates that the Company charges its customers.

If an electric utility purchases, acquires, merges, or consolidates with or acquires 50 percent or more of the stock of an electric utility or electric cooperative, the successor utility may be subject to regulation by the PUCT. Specifically, the PUCT would regulate the successor electric utility or electric cooperative in the same manner that they would regulate the entity that was subject to the stricter regulation before the purchase, acquisition, merger or consolidation. Therefore, if the Company is acquired by another entity or merges with another entity under circumstances where the Company is not the survivor, the acquiring entity or the surviving entity, would not be allowed to retain the treatment as an electric cooperative.

Management believes that the Company’s customers should have the ability to choose and the Company intends to eventually participate in retail competition. The Company is concerned, however, as to the implications of the

uncertainties that have arisen with respect to deregulation in the states where deregulation has occurred or is occurring, particularly those in the West and Southwest. In addition, there is still some uncertainty in Texas regarding whether the legislation that has been enacted will be modified or remain in its current form. The Company therefore believes that it is in the best interest of its customers to delay participation and defer incurring expenditures for upgraded systems and additional personnel that would be necessary to participate in retail competition until there is more certainty. The Company’s Board of Directors has elected not to opt in for competition at the present time.

The effect on the Company of deregulation in states other than Texas cannot be predicted because the Company only operates in Texas at the present time. However, if the Company subsequently acquires electric distribution businesses outside of Texas, the effect of deregulation in the state where the business is located could have a material, and possibly adverse, impact on the Company.

Federal Regulation

Federal legislation, such as the Public Utility Regulatory Policy Act of 1978 and, more recently, the National Energy Policy Act of 1992 and Texas legislation, such as the Public Utility Regulatory Act of 1995, as amended, have significantly altered competition in the electric utility industry. Among other things, the Public Utility Regulatory Policy Act and the National Energy Policy Act encourage wholesale competition among electric utility and non-utility power producers. The National Energy Policy Act addresses a wide range of energy issues and is intended to increase competition in electric generation and broaden access to electric transmission systems. At the state level, the Public Utility Regulatory Act encourages greater wholesale competition, flexible retail pricing and requires the PUCT to report to the Texas legislature on competition in electric markets. The Company does not engage in the power generation business.

The National Energy Policy Act empowers the Federal Energy Regulatory Commission to require utilities to provide transmission facilities for the delivery of wholesale power from other power producers to qualified resellers, such as municipalities, cooperatives and other utilities. The Company’s transmission facilities in its West Texas division, which are in the Southwest Power Pool, are subject to regulation by the Federal Energy Regulatory Commission, and the Company’s transmission facilities in its McCulloch division, which are part of the Electric Reliability Council of Texas, Inc., are subject to regulation by the PUCT. During 2002, the Company applied for, and FERC has approved, the unbundling of transmission rates to allow the full recovery of transmission costs of its West Texas transmission system. The unbundled tariff equals the tariff in the Company’s Open Access Transmission Tariff.

Competition and Restructuring

The Company faces strong competition in providing electric distribution services. Many of the Company’s competitors, like TXU Energy and its affiliate, Oncor, are much larger than the Company and have financial resources that are much greater than the Company’s. Oncor, which is the largest electric utility in the State of Texas in terms of revenues and size of operating areas, is certified to operate in many of the areas in West Texas where the Company currently operates and the Company competes with it on the basis of price and service. In many cases the Company’s prices are higher than those of Oncor, but the Company believes that it has retained many of its customers despite its prices because of the quality of the services it provides.

Legislation passed in Texas in 1999, which became effective January 2002, will significantly modify the industry and potentially introduce more competition into the Texas retail market. The Company’s customers may be able to purchase electricity from other providers at prices that are less than the Company may be able to provide. The level of competition is affected by several variables, including price, the cost of energy, alternative energy sources, new technologies and governmental regulations. The Company, however would remain as the distributor of such electricity. See “Business-State And Federal Regulation.”

Power Requirements

Currently, the Company purchases electric power through wholesale contracts with SPS, LCRA and Garland. In 2002, SPS, LCRA and Garland supplied approximately 71.4%, 12.9%, and 8.1%, respectively, of the Company’s electric power purchases. The Company also had a wholesale power contract with Dynegy which expired in 2002. Dynegy supplied approximately 7.6% of the Company’s electric power purchases for 2002. The Company negotiated and signed a

new contract with Garland which replaced the Dynegy contract and a previous contract with Texas-New Mexico Power Company. The contracts with SPS, LCRA and Garland will expire in 2013, 2016 and 2004, respectively. These contracts generally provide for pricing terms based upon the price of fuel and usage levels. We cannot predict what effect, if any, renegotiation of other expiring contracts may have on the Company’s financial condition and results of operations. However, all costs of power under the contracts are passed through to the retail customer.

Environmental Matters

The Company is subject to regulations with respect to certain environmental matters by federal and state authorities. The Company is unaware of any present or potential environmental problems and believes it is in compliance with all environmental regulations. Environmental regulations can change rapidly and are difficult to predict. Substantial expenditures may be required to comply with these regulations. The Company analyzes the potential costs arising from environmental matters on an ongoing basis, and management believes it has adequate provision in its financial statements to meet such obligations.

Construction and Capital Requirements

The Company has no major construction projects planned at the present time. Utility construction expenditures for 2003 will consist primarily of costs to maintain the Company’s transmission and distribution systems and to upgrade the information technology systems. Total gross property additions, including construction work in progress, for the year ended December 31, 2002, nine months ended December 31, 2002, and year ended March 31, 2001, were $1,517,000, $4,257,000 and $9,714,000, respectively. Our total estimated capital expenditures for the next three years are $5.4 million per year, which is contingent upon completion of financing arrangements.

Electric Market

In the United States, revenues from sales to ultimate consumers totals over $224 billion per year. It is an industry which is undergoing many changes. Deregulation occurred in Texas beginning in 2002, giving rise to significant opportunities and challenges for the Company. Many electric utility companies are significantly larger with greater resources than those of the Company. However, a significant number of electric utilities, especially electric cooperatives, are smaller in size and resources than the Company.

Many electric utility companies, particularly small shareholder owned and cooperative electric utility businesses, may not have the size or expertise to meet the demands of a newly competitive marketplace. The Company expects that as competition becomes more intense and operations become more complicated, more and more small to medium sized shareholder owned and cooperative electric utility businesses will want to divest their electric systems for some of the same reasons that the Company’s predecessor cooperative’s membership voted to convert from a member owned cooperative association to a shareholder owned business corporation.

In addition to the small to medium sized electric utility businesses that may be looking to divest their operations, management believes many of the larger shareholder owned electric utilities have been cutting costs by closing service centers in smaller communities and becoming more impersonal with their customers. Management of the Company believes these electric utilities are concentrating their efforts in the large urban populations and some may be looking to divest their holdings in rural and less populated suburban areas.

The Company’s management believes that it has the experience to consolidate these small to medium sized electric distribution businesses and to meet the management challenges of successfully operating these geographically diverse businesses once they have been acquired. The basis for this belief is that the Company has successfully combined, and is currently operating, three former electric distribution cooperatives, which are now divisions of the Company. The most distant of these divisions is over 450 miles from the Company’s corporate headquarters in Midland, Texas. The Company also currently provides management services to a municipal utility in North Texas. See “Business-Business Strategy.”

Business Strategy

The Company’s strategy involves acquiring customers in various locations and regions across the United States, irrespective of whether those customers may be for its electric distribution business or in other businesses in which the Company may engage. Notwithstanding, the Company’s experience to date has been in the electric distribution business and it is the Company’s desire to maintain that as its primary business. Once deregulation comes to an area, however, the Company wants to be in a position to market a diverse set of services to its customers. For this reason, the Company believes that an aggressive campaign of mergers and acquisitions will help it increase its customer base and thus put it in a position to compete effectively in a fully deregulated marketplace.

At present, the Company’s largest service area is in West Texas, where it primarily serves residential customers, farming and ranching customers and the oil and gas industry. In the case of the oil and gas industry, the Company’s revenues are not significantly affected by normal fluctuations in the price of oil and gas. The Company’s revenues are affected by the weather, economy and other conditions in their service areas, a circumstance that is not unusual for a local distribution company. The Company believes that it needs to diversify its customer base so that it is not dependent on any one area in terms of economy and weather. The Company believes that its strategy of acquiring electric distribution companies in various locations and regions across the United States is the best way for it to achieve this objective.

The larger electric utilities have traditionally been in areas with the most meters per mile of electric line. These are usually found in or around large cities and other metropolitan areas. The small to medium sized electric distribution businesses, on the other hand, are generally located in less-populated suburban and rural areas where there are fewer meters per mile of electric line and where the cost of service per meter is therefore greater. In the past, the larger utilities have, for the most part, viewed the areas where these small to medium sized electric distribution businesses operate as marginal because their operating areas generally do not provide the net revenues per dollar of investment that the larger utilities have come to expect. The Company therefore believes that as the electric utility industry continues to consolidate, the opportunity to acquire electric distribution businesses in less populated suburban and rural areas will remain below the economic threshold of many of the Company’s larger competitors, yet still provide the Company with a significant opportunity to grow and diversify.

The Company’s business strategy is a continuation of the Cooperative’s history of growing through acquisitions. The Cooperative acquired Lone Wolf Electric Cooperative, Inc., an electric cooperative headquartered in Colorado City, Texas, in 1991. All of the members of Lone Wolf became members of the Cooperative. The Lone Wolf acquisition was one of the first combinations of electric cooperatives to occur in the State of Texas.

In October 1992, the Cooperative acquired Hunt-Collin Electric Cooperative, Inc. Hunt-Collin was an electric cooperative headquartered in Celeste, Texas, serving customers in Hunt, Collin and Fannin counties of Northeast Texas. All the members of Hunt-Collin became members of the Cooperative. The Hunt-Collin acquisition was the first non-contiguous combination of cooperatives in the State of Texas and one of the first such acquisitions in the United States.

In October, 1998, the Cooperative entered into an agreement with the City of Farmersville, Texas, to manage and operate its municipal electric system, including billing, collections, system improvements, power acquisition, power outages, new construction and normal maintenance.

In September 1999, the Cooperative acquired McCulloch Electric Cooperative, Inc., an electric cooperative headquartered in Brady, Texas, with all of the members of McCulloch becoming members of the Cooperative.

In October 1999, the Cooperative entered into an agreement with Lamar Electric Cooperative, Inc. (“Lamar”), pursuant to which Lamar was to combine with, and become an operating division of, the Cooperative. The members of Lamar subsequently approved this Combination Agreement. The agreement provided that if the combination was terminated by Lamar, with certain specific allowable exceptions, Lamar was required to reimburse the Cooperative for all costs and expenses it had incurred, whether paid to outside parties or incurred internally, with respect to the combination.

The completion of the combination was delayed due to litigation with Lamar’s power supplier, Rayburn Country Electric Cooperative, Inc. (“Rayburn”). Rayburn filed suit against Lamar and the Cooperative claiming that each had breached various agreements. Rayburn sought and received an injunction preventing the combination from going

forward. Lamar and the Cooperative also filed lawsuits against Rayburn. The lawsuits are still pending and some claims are currently on appeal.

On August 29, 2000, the Cooperative and Lamar entered into a five year Management Service Agreement. Under the terms of that agreement, Lamar’s Board of Directors continued to set policy and perform all of its fiduciary responsibilities, and the Cooperative managed the day to day operations of Lamar and provided other services. As compensation for its management services, the Cooperative (subsequently the Company) received $1,000 per month plus reimbursed costs and expenses. One of the terms of the Management Service Agreement provided that if Lamar terminated the agreement prior to the expiration of the original term, Lamar would be required to pay a cancellation fee of $300,000 as liquidated damages.

Lamar terminated the Combination Agreement in October 2002 and the Management Service Agreement in November 2002. The Company is seeking remuneration pursuant to the terms of each of the agreements. See “Legal Proceedings” below.

ITEM 2. PROPERTIES

The West Texas transmission system consists of 16 substations and 305 miles of single pole transmission line that was constructed over a period of several years between 1975 and 1995. The system provides a looped transmission line at 138 kV that provides for two electric supply delivery points for power providers to tie into and deliver power. All substation structures and equipment are relatively new and utilize modern technologies. The substations and transmission lines are controlled by a Supervisory Control and Data Acquisition (“SCADA”) system. All present substation transformers have in-service dates between 1975 and 1995. Transmission systems normally carry high voltage electricity over long distances, whereas distribution lines carry lower voltage power from a substation to customers. The 16 substations supply sixty-six distribution line circuits, which serve over 11,000 miles of primary and secondary distribution line in 17 countywide areas and supplies approximately 120 MW of peak electrical power. When the transmission system was being constructed, a large portion of the distribution system was rebuilt to accommodate the new substations, as well as new feeder circuits being constructed with larger conductors and a higher distribution voltage. Many of the distribution circuits can also be fed from alternative substations in order to minimize outage time. The distribution system also utilizes a SCADA system.

The Company also owns a 50,000 square foot office building located at 500 West Wall Street, Midland, Texas, that is used as its general corporate headquarters. The Company occupies approximately 30% of the building and the remainder is leased to commercial tenants. In addition to the office building, the Company owns other real estate related to its electric distribution business.

ITEM 3. LEGAL PROCEEDINGS

The Company is involved in various litigation matters which it inherited from its predecessor cooperative, as well as litigation since its conversion from an electric cooperative to a shareholder owned utility.

In September 2001, the Cooperative and the Company filed an application to transfer the Cooperative’s certified territory to the Company. This was the last step in the conversion process. Several parties intervened in that proceeding and are seeking to stop the transfer of the CCN. Alternatively, these Opposing Intervenors are requesting a ruling that the Company will be regulated as a shareholder owned utility by the PUCT rather than as a cooperative. The Public Utility Regulatory Act currently provides that a successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the members of the electric cooperative, will be considered as a cooperative for regulatory purposes. The Opposing Intervenors argue that the Company does not qualify for such treatment and have attacked the validity of the vote of the Cooperative’s members that approved the conversion process. The Opposing Intervenors have also requested the PUCT to require the Company to “unwind” the conversion or, if it is determined that the conversion cannot be “unwound,” to regulate the Company as a shareholder owned utility for state regulatory purposes. As another alternative, the Opposing Intervenors seek to have restrictions placed on the Company if the CCN is transferred. As a result, until there is a Final Order by the PUCT on this issue, it is uncertain whether or not the Company will be considered a cooperative or a shareholder owned utility for State regulatory purposes or, if the Company is determined not to be a shareholder owned utility for state regulatory purposes, whether any restrictions will be placed

upon the Company’s operations. Delays in receiving final approval may impact the Company’s timing and ability to refinance its debt. The Company cannot predict all potential ramifications that may occur as a result of regulation by the PUC, some of which could be material. While the Company believes it will ultimately prevail, it is impossible to predict the outcome of these proceedings or any restrictions that the PUC may place upon the Company.

A hearing was held before Administrative Law Judges in Austin, Texas, on June 17 through June 21, 2002. Briefs were filed and the hearing was officially closed on July 30, 2002. A Proposal for Decision (“PFD”) was issued by the Administrative Law Judges on September 25, 2002. The PFD recommended that the Company be found to have taken proper steps to qualify for continued treatment as a cooperative under PURA. It further recommended that the CCN be transferred. The PFD also recommended that the Company be required to comply with certain conditions as part of the transfer of the CCN. Those conditions would require the Company to reduce its administrative and general expenses to no more than 30% of its gross margins, prohibition from making future acquisitions that are unrelated to providing reliable electric service to its existing customers, require any acquisitions to first be approved by the PUC, require maintenance of separate books and records for its electric divisions which are distinct from its existing subsidiary and non-electric operations, and require filing of outage reports under PUCT Substantive Rules 25.52 and 25.81.

The PFD was considered by the PUCT at an open meeting held on November 7, 2002. At the open meeting, the PUCT made no ruling, but requested the Company and the Opposing Intervenors file briefs in response to questions outlined by the Commissioners. Briefs were filed and the matter was set to be considered at another PUCT open meeting held on November 21, 2002. At that open meeting, the PUCT made no ruling, but requested an opinion from the Attorney General of the State of Texas as to whether an electric cooperative may convert to a shareholder corporation by transferring all of its assets and liabilities to a shareholder-owned corporation that it had created. The Attorney General has not yet rendered an opinion. Once the opinion from the Attorney General’s office has been rendered, the matter will again go before the PUCT for consideration

In 2002, the Company and the Cooperative filed a lawsuit against some of the Intervenors in the CCN proceeding and others who are trying to overturn the conversion plan. The Company and the Cooperative are seeking a declaratory judgment and other relief in that none of the defendants, nor any other person or entity, has standing to challenge the Cooperative’s “conversion” by transferring all of its assets and liabilities to the Company. The lawsuit is in the early discovery stages and while it is impossible to predict the outcome at this time, the Company believes it has adequate legal standing to prevail with regard to the validity of its claims.

In October 1999, the Cooperative entered into an agreement with Lamar, pursuant to which Lamar was to combine with, and become an operating division of, the Cooperative. The members of Lamar subsequently approved this Combination Agreement. The agreement provided that if the combination was terminated by Lamar, with certain specific allowable exceptions, Lamar was required to reimburse the Cooperative for all costs and expenses it had incurred, whether paid to outside parties or incurred internally, with respect to the combination.

Lamar terminated the Combination Agreement in October 2002 and the Management Services Agreement in November 2002. The Company believes that Lamar’s stated reason for termination of the Combination Agreement does not fall within the specific allowable exceptions set forth in the agreement, and therefore the Company believes it is

entitled to reimbursement of all costs and expenses incurred. Outside legal and consulting fees of approximately $1,357,000 were incurred, as well as other recoverable costs. The Company has assessed its rights under the agreement and believes it is entitled to reimbursement for all costs and expenses. The Company is currently compiling that data in order to determine the total recoverable costs it will seek under the provisions of the Combination Agreement. The Company is also seeking the cancellation fee of $300,000 pursuant to the terms of the Management Service Agreement, which it believes it is entitled to recover.

Because Lamar terminated the Combination Agreement, SFAS No. 141 required the impairment of those outside legal and consulting costs of $1,357,000, until reimbursement is actually received from Lamar. Therefore the consolidated results of operations reflect such expense for the year ended December 31, 2002, with those costs as of December 31, 2001, aggregating $956,000 shown in Deferred credits on the balance sheet.

The above matters are currently the subject of a lawsuit in the 62nd District Court in Lamar County, Texas.

In March 2002, the Cooperative received a demand letter from an attorney claiming to represent members or shareholders of the Cooperative. Such letter purports to be a derivative action demand under Article 5.14 section C of the Texas Business Corporation Act. The letter generally asserts wrongdoing by the Board and management because the vote at the October 20, 1998, membership meeting at which the conversion plan was adopted was not a valid vote. The Cooperative believes the claims outlined in the letter have no merit and responded accordingly to the letter. No further demands have been received and no legal action has been taken.

Other than certain legal proceedings arising in the ordinary course of business and the aforementioned legal matters, there is no other litigation pending or threatened against the Company. As discussed in “Notes to the Consolidated Financial Statements” included herein, none of this litigation is expected to have a material impact on the Company’s financial condition, operating results or liquidity.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

The Annual Meeting of Shareholders was held on December 2, 2002. The following proposals were adopted by the margins indicated:

1. To elect two directors to hold office until 2005

	Number of Shares
	For	Against
Michael D. Schaffner	546,040	7,048
Newell W. Tate	545,746	7,342

2. To approve Amendments to the Cap Rock Energy Corporation Employee Stock Purchase Plan

For		444,251
Against		7,161
Abstain		33,491
Broker non-vote		68,185

3. To approve amendments to the Cap Rock Energy Corporation Stock Incentive Plan

For		439,454
Against		6,794
Abstain		38,655
Broker non-vote		68,185

4. To approve the Cap Rock Energy Corporation Stock for Compensation Plan

For		436,740
Against		7,721
Abstain		40,442
Broker non-vote		68,185

5. To ratify the appointment of KPMG LLP as independent public accountants for 2002

For		543,376
Against		4,084
Abstain		5,628
Broker non-vote		-0-

Executive Officers of the Registrant

The executive officers of the Company are as follows:

NAME	AGE	POSITION
David W. Pruitt	56	Co-Chairman of the Board, President and Chief Executive Officer

Ulen A. North. Jr.	58	Executive Vice President

Lee D. Atkins	59	Senior Vice President, Chief Financial Officer and Treasurer

Sammy C. Prough	52	Vice President and Chief Operating Officer

Ronald W. Lyon	47	Vice President, General Counsel and Secretary

Celia A. Zinn	54	Vice President, Controller and Assistant Secretary/Treasurer

• David W. Pruitt has served as President and Chief Executive Officer of the Company since its inception. Mr. Pruitt also served as the President and Chief Executive Officer of the Cooperative from August 1987 until inception of the Company.

• Ulen A. North Jr. has served as Executive Vice President of the Company since its inception. He served the Cooperative in various positions from March 1969, and served as Executive Vice President of the Cooperative since December 1996 until inception of the Company.

• Lee D. Atkins has served as Senior Vice President and Chief Financial Officer of the Company since September 2001. He served as Executive Vice President/Chief Financial Officer of RedMeteor.com, Inc. from August 2000 until September 2001, and as Vice President/CFO of CSW Energy from February 1992 until August 2000.

• Sammy C. Prough has served as Vice President and Chief Operating Officer of the Company since its inception. Mr. Prough served the Cooperative in various positions since April 1974, including Systems Manager from October 1996 to June 1999 and Vice President and Chief Operating Officer since June 1999 until inception of the Company.

• Ronald W. Lyon has served as Vice President and General Counsel of the Company since October 2001. Mr. Lyon, who has been engaged in the private practice of law for more than the past five years, served as full-time general counsel to the Cooperative since 1993 until inception of the Company.

• Celia A. Zinn joined the Company as Controller in July 2001, and was elected to serve as Assistant Secretary/Treasurer in August 2002, and Vice President in December 2002. She previously served as Senior Vice

President and Controller of Costilla Energy, Inc. from April 1996 until July 2001. Ms. Zinn is a certified public accountant.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Price Range and Holders of Common Stock

The Company’s common stock is listed on the American Stock Exchange under the symbol “RKE.” The Company’s common stock was initially issued on February 8, 2002, and began trading on the American Stock Exchange on March 14, 2002. The following table sets forth the range of high and low sales prices per share of common stock for the periods indicated, as reported on the American Stock Exchange. Because the stock was not issued and distributed to former members of the Cooperative until February 8, 2002, and the stock was not listed on the AMEX until March 14, 2002, there was no previous market for the shares.

Quarter Ended:	High		Low
December 31, 2002	$	11.65	$	10.10
September 30, 2002	12.35		11.25
June 30, 2002	12.60		7.20

As of March 24, 2003, there were 13,744 record holders of the 1,302,355 shares of the Company’s common stock.

Dividend Policy

Holders of the Company’s common stock are entitled to dividends if, as and when declared by the Board of Directors out of funds legally available therefore, subject to prior rights of holders of any outstanding cumulative preferred stock. The Company has not declared or paid dividends on its common stock to date, and does not anticipate paying dividends in the foreseeable future. The Company’s loan documents with CFC place certain restrictions on the payment by the Company of dividends. At the present time, the Company has not issued preferred stock.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth certain information regarding the Company’s equity compensation plans as of December 31, 2002:

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	—	—	1,300,000
Equity compensation plans not approved by security holders	—	—	—
Total	—	—	1,300,000

ITEM 6. SELECTED FINANCIAL DATA

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth selected consolidated financial statement information for the year ended December 31, 2002, nine month periods ended December 31, 2001 and 2000, and for each of the three years in the three year period ended March 31, 2001. The Consolidated Statements of Operations, Balance Sheet and Cash Flows Data for the year ended December 31, 2002, nine months ended December 31, 2001 and 2000, and as of the end of each of the years in the three year period ended March 31, 2001, are derived from the Consolidated Financial Statements of the Company. The following selected consolidated financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements, including the Notes thereto, appearing elsewhere herein.

	YEAR ENDED DECEMBER 31,			NINE MONTHS ENDED DECEMBER 31,						YEARS ENDED MARCH 31,
	2002			2001 (3)			2000			2001			2000(1)			1999
							(UNAUDITED)
	- - - - - - - - -- - - - - - - - - - - - - - - - - - - (Thousands of dollars)- - - - - - - - - - - - - - - - - - - - - - - - - - -

CONSOLIDATED STATEMENT OF OPERATIONS DATA:

Operating revenues	$	74,637		$	53,122		$	52,100		$	72,465		$	56,391		$	54,803
Operating expenses	(59,964		)	(43,142		)	(50,101		)	(68,144		)	(51,773		)	(49,193		)
Operating income	14,673			9,980			1,999			4,321			4,618			5,610
Other income (expense)	(5,483		)	(5,580		)	(6,884		)	(9,471		)	(10,357		)	(5,223		)
Income (loss) before income taxes	9,190			4,430			(4,885		)	(5,150		)	(5,739		)	387
Income tax expense	414			—			—			—			—			—
Income (loss) before extraordinary item	8,776			4,430			(4,885		)	(5,150		)	(5,739		)	387
Extraordinary item– Gain on early extinguishment of debt (2)	—			—			969			969			—			—
Net income (loss)	$	8,776		$	4,430		$	(3,916	)	$	(4,181	)	$	(5,739	)	$	387

PRO FORMA BASIC AND DILUTED EARNINGS PER SHARE (UNAUDITED):

Income (loss) from continuing operations				$	3.40					$	(3.95	)
Extraordinary item (2)				—						0.74
Net income (loss)				$	3.40					$	(3.21	)
Pro forma shares outstanding				1,302,355						1,302,355

BASIC AND DILUTED EARNINGS PER SHARE:
Net income	$	6.74
Shares outstanding	1,302,355

	DECEMBER 31,									MARCH 31,
	2002			2001			2000			2001			2000			1999
							(UNAUDITED)
	- - - - - - - - - - - - - - - - - - - - - - - - - - - - - (Thousands of dollars) - - - - - - - - - -- - - - - - - - - - - - - - - - - -

CONSOLIDATED BALANCE SHEET DATA:

Utility plant, net	$	157,323		$	164,547		$	170,111		$	168,920		$	169,537		$	155,567
Total assets	211,294			214,459			218,382			221,195			200,881			181,983
Equity and margins	—			7,672			6,012			5,675			12,659			19,245
Long-term debt, net	148,052			181,732			184,688			188,627			140,333			125,625
Stockholders’ equity	14,738			—			—			—			—			—

CONSOLIDATED CASH FLOWS:
Net cash provided by (used) in:
Operating activities	13,250			11,257			5,732			7,022			7,200			8,674
Investing activities	526			(2,233		)	(23,867		)	(23,414		)	(14,124		)	(10,004		)
Financing activities	(9,375		)	(9,262		)	17,423			20,597			7,065			1,382

(1) The Cooperative acquired McCulloch Electric Cooperative, Inc. (“McCulloch”) effective September 1, 1999. McCulloch’s operations subsequent to the acquisition are included in the consolidated statement of operations.

(2) As discussed in Note 13 to the consolidated financial statements included herein, substantially all of the McCulloch long-term debt was refinanced resulting in an extraordinary gain on early extinguishment of debt of $969,000.

(3) The Company changed its year-end from March 31 to December 31, effective December 31, 2001.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

In the interest of providing the shareholders with certain information regarding the Company’s future plans and operations, certain statements set forth in this Form 10-K relate to management’s future plans and objectives. This Form 10-K contains statements that are “forward-looking statements” under the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts included in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or similar terminology. Although any forward-looking statements contained in this Form 10-K or otherwise expressed by or on behalf of the Company are, to the knowledge and in the judgment of the officers and directors of the Company, believed to be reasonable, there can be no assurances that any of these expectations will prove correct or that any of the actions that are planned will be taken. Forward-looking statements involve known and unknown risks and uncertainties, which may cause the Company’s actual performance, and financial results in future periods to differ materially from any projection, estimate or forecasted result. Important factors that could cause actual results to differ materially from the Company expectations include the effects of deregulation and related proceedings, weather, the cost of purchased power and related fuel costs. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the Cautionary Statements. The Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations.

The following discussion and analysis of the Company and its Predecessor’s financial condition and results of operations for the years ended December 31, 2002 and 2001, and the nine months ended December 31, 2001 and 2000, should be read in conjunction with the Company’s audited consolidated financial statements and related notes to financial statements included elsewhere in this document.

Overview

Cap Rock Energy Corporation is an electric distribution company operating in various non-contiguous areas in the State of Texas. The Company provides service to over 35,000 meters in 28 counties in Texas. This includes 23,000 meters in 17 counties in the Midland-Odessa area of West Texas, 6,100 meters in the Central Texas area around Brady, Texas, and over 4,200 meters in Northeast Texas in Hunt, Collin and Fannin Counties. The Company also provides management services to the Farmersville Municipal Electric System which services nearly 1,700 meters in Farmersville, Texas.

The Company purchases power for resale to its retail customers from wholesale suppliers and distributes that power to its customers over transmission lines covering over 320 miles and then over 11,000 miles of distribution lines. The Company has not and does not plan to engage in the generation of electricity. The Company’s primary focus is on the distribution of electricity to its customers. In 2002, the Company purchased all electric power pursuant to wholesale electric power contracts with Southwestern Public Service Company, Dynegy Power Marketing, Inc., Lower Colorado River Authority and Garland Power and Light. Generally, the wholesale electric power supply contracts are based on fixed charges for kWh usage, transportation and auxiliary services and a variable charge for fuel based on kWh usage. The Company’s purchased power costs fluctuate primarily with the price of natural gas. However, all costs associated with purchased power are passed through to the retail customer.

The Board of Directors adopted a resolution changing the date of the Company’s and the Cooperative’s fiscal year end from March 31 to December 31, effective for the year ended December 31, 2001.

Critical Accounting Policies and Estimates

The Company’s significant accounting policies are in Note 1 to the consolidated financial statements. Certain of our accounting policies require the application of significant judgment by management in selecting the appropriate assumptions for calculating financial estimates. By their nature, these judgments are subject to an inherent degree of uncertainty. These judgments are based on our historical experience, terms of existing contracts, our observance of trends in the industry, information provided by our customers, and information available from other outside sources, as appropriate. Different estimates reasonably could have been used in the current period, or changes in the accounting estimates are reasonably likely to occur from period to period, that could have a material impact on the presentation of the Company’s financial condition, changes in financial condition or results of operations. We believe that the following financial estimates are both important to the portrayal of the Company’s financial condition and results of operations and require subjective or complex judgments. Further, we believe that the items discussed below are properly recorded in the financial statements for all periods presented. Management has discussed the development, selection and disclosure of our most critical financial estimates with the Board of Directors’ Audit Committee.

The Company’s most significant accounting policies are described in Note 1 to the consolidated financial statements. The Company’s most critical accounting policy involves rate regulation. The Company is subject to the provisions of Financial Accounting Standards Board (“SFAS”) Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” In certain circumstances, SFAS No. 71 requires that certain costs and/or obligations be reflected in a deferral account on the balance sheet and not reflected in the statement of income or loss until matching revenues are recognized. It is the Company’s policy to assess the recoverability of costs recognized as regulatory assets and Company’s ability to continue to account for its activities in accordance with SFAS No. 71, based on each regulatory action and the criteria set forth in SFAS No. 71.

Allowance for doubtful accounts. When evaluating the adequacy of our allowance for doubtful accounts, management analyzes accounts receivable, historical bad debts, customer credit-worthiness, current customer payment performance and current economic trends. For the year ended December 31, 2002, nine months ended December 31, 2001 and year ended March 31, 2001, the bad debt expense was less than one tenth of one percent of electric sales in each respective year.

Our accounts receivable balance was $4,723,000 and $3,642,000, net of allowance for doubtful accounts of $50,000 and $202,000, at December 31, 2002 and 2001, respectively.

Power Cost Recovery Factor. The power cost recovery factor is the difference between the cost of purchased power and the cost recovered from the customers, divided by the number of kilowatt hours billed during the period. This factor is estimated each month to recover actual costs and is added to the base rate. The factor is based on estimates of power cost increases/decreases due to increases/decreases in fuel cost, usage and other cost fluctuations. The estimate is adjusted in the subsequent month as compared to actual activity.

Derivative Instruments and Hedging Activities. The Company enters into derivative transactions to manage the cost of natural gas as the fuel component of power cost. As described in note 1 to the consolidated financial statements, the pricing under the Company's various power contracts varies with fuel cost, which is generally determined by the cost of natural gas. These transactions minimize the fluctuations in their customers’ power bills. The instruments are measured at fair market value and recorded as an asset or liability with a corresponding regulatory asset or liability. Changes in the fair value are recognized in current earnings unless specific hedge accounting criteria are met.

Revenue Recognition Policy. For all periods through December 31, 2002, the Company and its predecessor, the Cooperative, utilized the cycle billing method to recognize revenue, pursuant to the rate-making policy as set by the Board of Directors. The cycle billing method recognizes revenue on an “as billed basis” which recognizes revenue when the customer is billed and not on an accrual basis, which recognizes revenue as the power is distributed to the customer. By utilizing the “as billed” method, unbilled revenue is not recognized. In the utility industry, the rate-making policy defines the accounting requirements according to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulations.”

Effective January 1, 2003, the Company’s Board of Directors changed the rate-making policy to recognize unbilled revenue. At such time, the Company will be required to change accounting principles related to its revenue recognition method. Under the new rate-making structure, the Company will recognize revenue when power is distributed to the customer rather than when the customer is billed.

Results of Operations

Year ended December 31, 2002 Compared With Year Ended December 31, 2001

Net Income (Loss)

For the year ended December 31, 2002, net income was $8,776,000 as compared to net income of $4,834,000 for the year ended December 31, 2001, an increase of $3,944,000. The majority of the increase is due to:

• An increase in operating revenues of $1.2 million;

• A net decrease in operating expenses of $0.7 million;

• A net decrease in other income (expense) of $2.4 million; offset by

• An increase in tax expense of $0.4 million.

Operating Revenues

Operating revenues for the year ended December 31, 2002, were $1,226,000 greater than those of the year ended December 31, 2001. The increase was due to the recognition of revenue related to the recovery of power cost, offset by a slight decrease in electric sales.

Operating Expenses

Operating expenses for 2002 and 2001, were $59,964,000 and $60,721,000, respectively, a decrease of $757,000, for the following reasons:

Purchased power cost decreased by $4.3 million due to high natural gas prices and fixed price contract losses during the early months of 2001. Natural gas prices affect the cost of power generation, which is passed through from our power suppliers. The decrease in purchase power cost was offset by an increase in general and administrative expense of $2.5 million and further offset by $1.3 million for the write off of deferred costs related to the termination of the Lamar combination. The increase in general and administration expense was primarily due to legal expenses associated with PUCT hearings, discussed in “Legal Proceedings,” and shareholder related costs.

Other Income (Expense)

Interest expense decreased by $3.7 million offset by a decrease in other income items of $1.3 million. Interest expense decreased due to a decline in variable interest rates. Long-term variable rates were 3.4% in December 2002 compared to 4.7% in December 2001. The line of credit interest rates were 3.65% and 5.1% for December 2002 and December 2001, respectively.

Income Taxes

Current income tax expense was $414,000 in 2002. There was no current income tax expense in 2001 due to utilization of net operating loss carryforwards. Prospectively, a strategy is available to defer a portion of income tax expense.

Nine Months Ended December 31, 2001 Compared With Nine Months Ended December 31, 2000

Net Income (Loss)

For the nine months ended December 31, 2001, net income was $4,430,000 as compared to net loss of $3,916,000 for the nine months ended December 31, 2000, an increase in net income of $8,346,000. The majority of the increase is due to:

• increase in revenues from electric sales of $1,674,000;

• decrease in the cost of purchased power by $4,185,000; and

• one time write offs of investments in 2000 for $3,878,000

Operating Revenues

Operating revenues for the nine months ended December 31, 2001, were $53,122,000 compared to $52,100,000 for the same period in 2000. The increase is attributable to rate increases for electric kWh sales and income recognition of $1.7 million associated with the recovery of power cost. The increases were partially offset by a 3% decrease in kWh sales to residential and commercial customers due to a milder summer.

Operating Expenses

Operating expenses for 2001 and 2000, were $51,146,000 and $58,004,000, respectively, a decrease of $6,858,000, (11.8%) for the following reasons:

Purchased power costs decreased by $4,185,000 (12.9%) between the nine month periods, from $32,379,000 in 2000, to $28,194,000 in 2001. The decrease is due to lower natural gas prices for power generation, which is passed through from our purchase power providers.

Operations and maintenance expense increased $344,000 (19%) between the two periods because of increased maintenance activities due to of the effects of weather damage (lightning in the late spring). Additionally, a preventive maintenance program was initiated in the spring of 2001.

Administrative and general expenses for the nine month period ended December 31, 2001, increased by $767,000 a 30% increase, over the comparable period in 2000. This was due to increased legal expenses associated with the transfer of the CCN, use of consultants for short-term projects, internal costs associated with the conversion process and the fulfillment of staffing needs relating to deregulation of electric utilities and filing requirements with the SEC.

The Company wrote off two investments during the year 2000: $2,815,000 was related to the Citizens transaction and $1,063,000 was written off for the investment in MDC. See Notes 6 and 7 to “Notes to Consolidated Financial Statements.” No write offs were recognized for the nine months ended December 31, 2001.

Operating Income

The nine months ended December 31, 2001, reflected operating income of $9,980,000, as compared to the same nine month period in 2000, which had operating income of $1,999,000. This resulted in an increase in operating income of $7,981,000. The increase was primarily attributable to the increase in sales and the decrease in operating expenses discussed above.

Other Income (Expense)

Other income for the nine months ended December 31, 2001, was $5,580,000 compared to $6,884,000 for the nine months ended December 31, 2000. The increase was primarily attributable to:

• A $385,000 increase in dividends from associated organizations; and

• $962,000 increase in interest income

Interest income, generated by a new note receivable, accounted for a large part of the increase. Other miscellaneous services provided to customers also contributed.

Extraordinary Items

As discussed in Note 13 to the consolidated financial statements, the Cooperative paid off certain long-term debt during 2000, resulting in an extraordinary gain of $969,000 on early extinguishment of debt.

Liquidity and Capital Resources

As of December 31, 2002 , the Company had:

• Cash and cash equivalents of $9,899,000;

• A working capital deficit of $4,555,000; and

• Long-term indebtedness of $148,052,000, net of current portion.

Historically, the Company’s primary sources of liquidity have been cash flows from operations and borrowings from CFC, the Company’s primary lender. These borrowings are collateralized by substantially all of the Company’s utility distribution assets. The existing long-term debt consists of a series of loans from CFC that impose various restrictive covenants, including the prohibition of additional secured indebtedness, or the guaranty of such, and requires the maintenance of a debt service coverage ratio as defined in the CFC loan agreements. In addition, the Company may not make any cash distribution or any general cancellation or abatement of charges for electric energy or services to its customers if the ratio of equity to total assets is less than a stated percentage. At December 31, 2002, the Company was in compliance with its CFC loan agreements or had obtained waivers of certain covenants therein that the Company was required to meet.

As of December 31, 2002, the Company had utilized all available borrowing capacity under the CFC loan agreements. Historically, the majority of the Company’s distribution property additions have been financed with long-term borrowings from CFC. In order for the Company to meet its working capital needs, debt service requirements, common stock purchase commitments and planned capital expenditures, the following options may be available:

• Securing new financing;

• Reducing short-term capital expenditures

• Selling or collateralizing non-strategic assets; and

• Refinancing existing debt obligations.

Additionally, effective December 1, 2002, the Company converted its existing long-term debt from variable interest rates to one-year, two-year and three-year fixed rates in order to minimize its interest rate exposure. Interest rates were fixed for the next three years at rates under 5%. Approximately 10% of the note balances were fixed for one year, 60% for two years and 30% for 3 years.

The Company has debt service payment obligations for the next 12 months as summarized below:

	Quarter ended
	March 31, 2002		June 30, 2002		September 30, 2003		December 31, 2003

Long-term debt payments	$	1,121	$	1,129	$	13,026	$	893
Capital lease payments	1,338		1,376		15,008		33
Total cash commitments	$	2,459	$	2,505	$	28,034	$	926

CFC has approved the conversion of the prior line of credit for $28 million to a five year term loan. The terms of the new arrangement include quarterly payments of approximately $233,000 based on a 30 year amortization schedule with a final balloon payment at the end of year five, initial principal payment deferral of one year and a fee of $210,000. The execution of the new loan documents is currently in progress. The $28 million term loan is not included in the above table due to deferral of any principal payments until 2004.

The Company anticipates receipt of payment for the United Fuel notes receivable balance of approximately $11.9 million prior to the scheduled maturity date because United Fuel is currently in discussions with lenders in order to obtain financing that would provide funds to allow United Fuel to fully repay the Company’s notes receivable. See Note 15 to the consolidated financial statements. These proceeds will be used to satisfy the cross-collateralized note payable of the same amount included in the table above under long-term debt payments. The maturity date for both the notes receivable and note payable is in the third quarter of 2003. If United Fuel is not successful in obtaining financing, the Company has other options available to obtain the funds necessary to satisfy its debt obligations. Also, in the event United Fuel is not successful in obtaining financing, United Fuel, or its shareholders who have provided the Company with personal guarantees of the notes receivable, would pay down the notes and provide funds to the Company such that the Company would together with its cash flow from operations, be able to satsify its debt obligations as they become due in 2003. The Company is also considering, as an alternative, an opportunity to extend the payment date of the note payable to the bank for $12,490,000 for an additional year.

The Company believes cash generated from normal operations will be sufficient to service the remaining debt obligations listed in the table above, which includes the transmission system capital lease balloon payment of approximately $14 million due in the third quarter of 2003. This capital lease balloon payment will be offset by sinking fund monies which will approximate $8 million at September 2003. The current sinking fund balance of approximately $7.4 million is reflected in Other current assets.

One of the Company’s subsidiaries, NewCorp Resources Electric Cooperative, Inc., owns a 305 mile transmission system in West Texas. Even though, as described above, there is sufficient cash flow to satisfy debt obligations, the Company is attempting to either refinance or sell this transmission system and has received various proposals to do so. The decision on which alternative best suits the Company’s needs will be based upon various factors such as the amount of sale or loan proceeds, documentation requirements, the regulatory approval process and management approval. Any proposed transaction would be subject to several conditions, including:

• Approval of the transaction by the Company’s Board of Directors and the appropriate management of the buyer or lender;

• Completion of any due diligence reviews;

• Execution by the parties of definitive agreements and all other necessary agreements; and

• Approval of regulatory agencies having jurisdiction over the transmission system, if applicable or necessary.

At the closing, funds would be used to repay all amounts owed with respect to the original transmission line financing, to fund any capital investment needs and to satisfy general corporate needs such as reserves for storm damage.

As discussed above in “Legal Proceedings” and in Note 26 to the consolidated financial statements, the Cooperative and the Company filed an application to transfer the Cooperative’s certified territory to the Company. This was the last step in the conversion process. The Company’s current ongoing negotiations to refinance the transmission system through a loan or sale could be delayed or interrupted due to the above mentioned issues relative to the PUCT and the CCN.

Commencing one year from the date of the distribution of the Company’s common stock to the former members of the Cooperative in connection with the conversion plan and ending 60 days thereafter, the Company offered to purchase at a price of $10 per share all of its shares of common stock that were distributed in connection with the Plan. The effect of the common stock purchase commitment is unknown because it is based on the number of shareholders who accept the offer. Shares of the Company’s common stock were originally distributed to certain former members of the Cooperative who elected to receive shares of stock as payment for their equity and membership interest in the Cooperative. Pursuant to the terms of the conversion plan, the Company made a commitment to purchase those shares, held continuously by the original owners of record until the first anniversary of the distribution of the shares at a price of $10 per share if the Company had sufficient cash available to purchase all shares tendered. The Company’s original purchase commitment was only to those shareholders who were the original holders of record, and who had held those shares continuously until the first anniversary of the distribution of the shares. In an effort to be inclusive, rather than exclusive, the Company has made the offer to all shareholders and extended the offering period beyond the original 60 days. The offering period began February 5, 2003, and will end April 30, 2003.

If all shareholders tendered their shares, the maximum amount of funds required would be $13,023,550. The Company currently has cash available from its operations of $550,000 with which to purchase tendered shares. While additional cash from operations may become available, the Company does not believe substantially more than 55,000 shares will be tendered. If the number of shares tendered exceeds the Company’s cash available to purchase all shares tendered at that time, the Company may extend the offer once in order to try to obtain the additional funds needed to purchase all of the shares properly tendered. If following such extension additional funds are not available to enable the Company to purchase all properly tendered shares, the Company will terminate the offer and return all shares tendered. The Company currently does not have any alternative financing arrangements or financing plans in the event available cash is insufficient to purchase all tendered shares

Contractual Obligations and Commitments

The following summarizes the Company’s significant obligations and commitments to make future contractual payments as of December 31, 2002. The Company has guaranteed the debt of other parties as discussed in Note 11 to the consolidated financial statements.

Borrowings under the Company’s mortgage notes were $151,423,000 at December 31, 2002, which includes the previous revolving line of credit that has been converted to a mortgage note. Annual maturities of the mortgage notes as of December 31, 2002, are as follows:

(In Thousands)

2003	$	3,680
2004	4,731
2005	8,295
2006	4,553
2007	28,961
Thereafter	101,204
	$	151,424

For additional information, see Note 13 to consolidated financial statements.

The capital lease obligation associated with the transmission system is due in September 2003. The Company has received various proposals to either refinance the debt associated with the transmission system or sell its transmission assets. For additional information concerning the capital lease, see Note 14 to the consolidated financial statements.

Required principal payments for the note payable and other capital leases as of December 31, 2002, were $12,920,000, of which $12,612,000 is due in 2003 with the remaining balance of $308,000 due in various installments through 2007. For additional information concerning note payable and other capital leases, see Notes 14 and 15 to the consolidated financial statements.

For information concerning commitments and contingencies, see Note 26 to consolidated financial statements.

For information related to power requirements and contracts, see “Power Requirements.”

Cash Flow Data

During the nine months ended December 31, 2001, cash provided from operations was $11,257,000. This represents an increase of $5,525,000 over the corresponding period in 2000. Significant items accounting for the increase include:

• an increase in net income of $8,346,000 as explained in the section “Results of Operations;”

• increase due to write off of investments in 2000; and

• offset by an increase in the change of the purchase power cost subject to refund of $5,216,000.

During the nine months ended December 31, 2001, cash out flows attributable to investing activities was $2,233,000 as compared with $23,867,000 in 2000. The decrease in cash flow, $21,634,000, is attributable to:

• a reduction in capital investments in plant additions of $4,018,000;

• reduction in nonutility assets of $849,000;

• note receivables issued of $14,667,000 in 2000; and

• offset by payments received on a note receivable in the amount of $2,100,000.

During the nine months ended December 31, 2001, cash used in financing activities was $9,262,000 as compared to $17,423,000 provided by financing activities during the corresponding period in 2000. This decrease of $26,685,000 was primarily due to:

• proceeds from issuance of mortgage notes of $14,917,000 in 2000;

• issuance of note payable in 2000 of $15,000,000;

• lower CFC loan payments of $5,269,000 in 2001 as compared to 2000; and

• rescission offer discounted cash payments of $1,118,000 in 2001.

New Accounting Standards

On August 15, 2001, the FASB issued SFAS No. 143, “Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is required for adoption for fiscal years beginning after June 14, 2002. The Company anticipates that the adoption of SFAS No. 143 will not have a significant effect on its results of operations or financial position.

In July 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. The Company anticipates that the adoption of SFAS No. 146 will not have a significant effect on its results of operations or financial position.

In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 requires a guarantor to recognize a liability, at the inception of the guarantee, for the fair value of obligations it has undertaken in issuing the guarantee and also include more detailed disclosures with respect to guarantees. FIN 45 is effective for guarantees issued or modified after December 31, 2002 and requires the additional disclosures for interim or annual periods ended after December 15, 2002. The Company does not expect that the provisions of FIN 45 will have a material impact on its results of operations or financial position.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities — an interpretation of ARB No. 51” (“FIN 46”). FIN 46 requires that if an entity has a controlling financial interest in a variable interest entity, the assets, liabilities and results of activities of the variable interest entity should be included in the consolidated financial statements of the entity. FIN 46 requires that its provisions are effective immediately for all arrangements entered into after January 31, 2003. For those arrangements entered into prior to January 31, 2003, the FIN

46 provisions are required to be adopted at the beginning of the first interim or annual period beginning after June 15, 2003. The Company does not expect that the provisions of FIN 46 will have a material impact on the Company’s results of operations or financial position.

In December, 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation,” Transition and Disclosure, an amendment of FASB Statement No. 123 (SFAS No. 148). SFAS No. 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123), to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company has adopted the intrinsic method of accounting for its stock-based compensation. The Company does not believe that the provisions of SFAS No. 148 will have a material impact on the Company’s results of operations or financial position.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk represents the risk of changes in the value of a financial instrument, derivative or non-derivative, caused by fluctuations in interest rates, foreign currency exchange rates, prices of commodities and equity price risks.

Commodity Price Risk

All purchases of electricity are pursuant to long-term wholesale electric power contracts based on a fixed price for kWh usage, transportation and auxiliary services and a variable charge for fuel cost, which is generally natural gas. All of the actual costs associated with the purchase of electricity are able to be recovered from billings to our customers, which mitigates most of the risk of variations in gas costs.

In the first quarter of 2001, the Company entered into two derivative transactions to fix a portion of the natural gas component of the related power costs over the next twelve months to minimize the fluctuations in their customer’s power bills. These transactions fixed the price on approximately 35,000 to 260,000 MMBtus of natural gas at fixed prices ranging from $3.79 to $5.31 an MMBtu. All payments made or received in connection with these transactions were collected or rebated to the customers through the power cost recovery component of the customers’ power bills. The last derivative contract expired in May 2002. The Company uses this type of instrument to manage costs for its customers.

Credit Risk

The Company’s concentrations of credit risk consist primarily of cash, trade accounts receivable, sales concentrations with certain customers and a note receivable from a third party.

Credit risk with financial institutions is considered minimal because of the number and various physical locations of different financial institutions utilized. The Company has utilized repurchase agreements, and may consider using that vehicle again in the future to maximize return and minimize credit risk.

The Company conducts credit evaluations of new customers and assesses the need for a deposit by that customer. The deposit amount is normally set as 1/6 of an annual customer billing, with such amounts being refunded or credited to the customer after one year if they have paid timely at least 10 of the last 12 billings. No customer accounted for 10% or more of operating revenues of the Company.

In connection with an investment in United Fuel and Energy Corporation, the Company has a note receivable from United Fuel with a current balance of $13,667,000, with a final balloon payment due in July 2003. The interest rate is variable, and is tied to the interest rate on the Company’s note payable to a bank.

Interest Rate Risk

We are subject to market risk associated with interest rates on our CFC long-term indebtedness. The Company’s mortgage debt with CFC allows for a change from variable rate to fixed rate with no additional fees. In order to take advantage of the interest rate environment in late 2002 as well as employ an interest rate management strategy, the Company fixed the interest rates on $11,525,000 of its debt at 3.35% for a period of one year, on $70,519,000 at 4.20% for a period of two years and on $35,189,000 at 4.70% for a period of three years. At December 31, 2002, there was $28,000,000 at an average variable rate of 3.9% and $6,187,000 at a fixed rate of 6.5%. Pursuant to the terms of the mortgage notes, our variable debt with CFC is CFC prime rate plus 1%. A 1% increase in interest rates results in an approximate increase of $280,000 in interest expense.

Company Purchase Commitment

Shares of the Company’s common stock were originally distributed to certain former members of the Cooperative who elected to receive shares of stock as payment for their equity and membership interest in the Cooperative. Pursuant to the terms of the conversion plan, the Company made a commitment to offer to purchase those shares, held continuously by the original owners of record until the first anniversary of the distribution of the shares at a price of $10 per share if the Company had sufficient cash available to purchase all shares tendered. Although the original purchase commitment was only to original holders, the Company, in its desire to be inclusive rather than exclusive, has extended the offer to all shareholders. The offering period began February 5, 2003, and will end April 30, 2003.

The effect of the common stock purchase commitment is unknown because it is based on the number of eligible shareholders who accept the offer. If all shareholders tendered their shares, the maximum amount of funds required would be $13,023,055. The Company currently has cash available from its operations of $550,000 with which to purchase tendered shares. While additional cash from operations may become available, the Company does not believe substantially more than 55,000 shares will be tendered. If the number of shares tendered exceeds the Company’s cash available to purchase all shares tendered at that time, the Company may extend the offer once in order to try to obtain the additional funds needed to purchase all of the shares properly tendered. If following such extension additional funds are not available to enable the Company to purchase all properly tendered shares, the Company will terminate the offer and return all shares tendered. The Company currently does not have any alternative financing arrangements or financing plans in the event available cash is insufficient to purchase all tendered shares.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements are set forth on pages F-1 through F-32 of this Form 10-K.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Effective July 26, 2002, the Audit Committee dismissed Arthur Andersen LLP (“Arthur Andersen”) as the Company’s independent accountants and engaged KPMG LLP (“KPMG”) to serve as the Company’s independent accountants for the year ended December 31, 2002, as reported on Form 8-K dated July 26, 2002.

The reports of Arthur Andersen on the financial statements of the Company’s predecessor, Cap Rock Electric Cooperative, Inc. for the year and period ended March 31, 2001, and December 31, 2001, did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles.

During the Cooperative’s year ended March 31, 2001, and period ended December 31, 2001, as well as the subsequent interim period through July 26, 2002, for both the Company and the Cooperative, there were no disagreements with Arthur Andersen on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedures, which agreements, if not resolved to the satisfaction of Arthur Andersen, would have caused Arthur Andersen to make reference to the subject matter of the disagreements in connection with its reports.

The Company requested that Arthur Andersen furnish a letter addressed to the SEC stating whether or not it agrees with the above statements. The Company understands that it will be unable to obtain that letter.

During the Cooperative’s year ended March 31, 2001, and its period ended December 31, 2001, and the Company’s subsequent interim period through July 26, 2002, KPMG has not been engaged as an independent accountant to audit either the Cooperative’s or the Company’s financial statements or the financial statements of any of their consolidated subsidiaries, nor has KPMG been consulted regarding the application of the Company’s accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Company’s financial statements, or any other matters or reportable events listed in Items 304(a)(2)(i) and (ii) of Regulation S-K.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors And Executive Officers

The information required by this item concerning the Company’s executive officers is included in Part I, Item 4, of this Form 10-K.

The following table sets forth certain information regarding the directors of the Company as of December 31, 2002:

NAME	AGE	POSITION
David W. Pruitt	56	Co-Chairman of the Board, President and Chief Executive Officer

Michael D. Schaffner (1)	55	Director

Russell E. Jones (1)	57	Co-Chairman of the Board

Sammie D. Buchanan (1) (2)	59	Director

Jerry R. Hoelscher (1) (2) (3)	53	Director

Floyd L. Ritchey (1) (2)	64	Director

Newell W. Tate (1)	73	Director

(1) Audit Committee

(2) Compensation Committee

(3) Mr. Hoelscher resigned from the Board in January 2003 for personal reasons.

Set forth below is a description of the background of each of the directors of the Company:

• David W. Pruitt has served as a director of the Company since its inception and was elected as a Co-Chairman of the Board in February 2001. He currently serves as the President and Chief Executive Officer of the Company. Mr. Pruitt also served as the President and Chief Executive Officer of the Cooperative from August 1987 until inception of the Company. Mr. Pruitt’s term as director expires in 2004.

• Michael D. Schaffner has served as a director of the Company since October 1999. He also served as a director of the Cooperative from October 1999, and prior to that he served as a director of McCulloch Electric Cooperative, Inc., a cooperative that consolidated into the Cooperative. Mr. Schaffner is engaged in public accounting in Brady, Texas, and has owned his own accounting firm for more than the past five years. Mr. Schaffner’s term expires in 2005.

• Russell E. “Rusty” Jones has been a director of the Company since its inception and currently serves as Co-Chairman of the Board of the Company. Mr. Jones served as a member of the Board of Directors of the Cooperative since September 1979 and until inception of the Company. Mr. Jones has been a farmer and rancher for his entire business career, including owning and operating his own agricultural businesses for more than the past five years. Mr. Jones’ term expires in 2004.

• Sammie D. Buchanan has been a director of the Company since its inception. He served as a director of the Cooperative from September 1975 until inception of the Company. Mr. Buchanan has been a farmer and rancher for his entire business career, including owning and operating his own agricultural businesses for more than the past five years. Mr. Buchanan’s term expires in 2003.

• Jerry R. Hoelscher had been a director of the Company since its inception and served as a director of the Cooperative from February 1995 until inception of the Company. Mr. Hoelscher has been a farmer and rancher for his entire business career, including owning and operating his own agricultural businesses for more than the past five years. Mr. Hoelscher resigned from the Board in January 2003. His term was set to expire in 2003.

• Floyd L. Ritchey has been a director of the Company since its inception. He served as a director of the Cooperative from February 1998 until inception of the Company, and prior to that he served as a director of Lone Wolf Electric Cooperative, Inc., a cooperative that consolidated into the Cooperative. Mr. Ritchey has been a farmer and rancher for his entire business career, including owning and operating his own agricultural businesses for more than the past five years. Mr. Ritchey’s term expires in 2003.

• Newell W. Tate has been a director of the Company since its inception. He served as a director of the Cooperative from September 1986 until inception of the Company. Mr. Tate has been a farmer for his entire business career, including owning and operating his own agricultural businesses for more than the past five years. Mr. Tate’s term expires in 2005.

Section 16 (a) Beneficial Ownership Reporting Compliance

Section 16 (a) of the Securities Exchange Act of 1934, as amended, requires the Company’s directors and executive officers and persons who own more than 10% of a registered class of the Company’s equity securities (collectively, the “Reporting Persons”) to file reports of ownership on Form 3 and changes in ownership on Form 4 or Form 5 with the Securities and Exchange Commission. The Reporting Persons are also required to furnish the Company with copies of all Section 16 (a) reports they file.

Celia A. Zinn filed Form 3, “Initial Statement of Beneficial Ownership of Securities” on March 24, 2003, pursuant to her election as Vice President on December 2, 2002. No transactions occurred which were required to be reported prior to March 24, 2003.

Based solely upon a review of the copies of these reports furnished to us, all persons subject to the reporting requirements of Section 16 (a), with the aforementioned exception, filed the required reports on a timely basis for the year ended December 31, 2002.

ITEM 11. EXECUTIVE COMPENSATION

Compensation of Directors

Each of our directors, with the exception of David W. Pruitt, is considered an outside director because they are not salaried employees of the Company. In 2002, the standard arrangements for compensation of Board members was as follows:

• committee meeting attendance and telephone meeting fees were changed to $500 and $250, respectively;

• stock awards of $10,000 annually, with each director having the option to choose all stock, or half stock and half cash;

• outside directors who resign from the Board, become advisory directors and were former directors of the Cooperative will receive the same benefits as a director for up to six years. If the advisory director should resign during the six year period, he will be entitled to receive stock options for 35,000 shares at an exercise price based on market price;

• outside directors who resign from the Board, choose not to become an advisory director, but were former directors of the Cooperative will receive stock options for 35,000 shares at an exercise price based on market price.

In addition, directors participate in the Achievement Based Compensation Contract - Merger or Acquisition with Other Electric Utilities. See “Compensation Committee Report” for a discussion of that plan.

Compensation of Named Executive Officers

The following table describes the compensation paid to our President and Chief Executive Officer and each of the other executive officers with total salary and bonus in excess of $100,000 for services rendered during the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001.

		Annual Compensation						All Other Compensation (b)
						Other Annual Compensation (a)
Name and Position	Year	Salary		Bonus		Other Annual Compensation (a)
David W. Pruitt	Twelve Months Ended December 31, 2002	$	214,995	$	39,001	$	100,795	$	118,868
Co-Chairman of the Board,	Nine Months Ended December 31, 2001	155,734		82,948		18,046		19,085
President and Chief Executive Officer	Twelve Months Ended March 31, 2001	181,009		116,383		16,497		49,035

Ulen A. North, Jr.	Twelve Months Ended December 31, 2002	110,879		$	39,001	41,880		66,345
Executive Vice President	Nine Months Ended December 31, 2001	89,200		32,845		8,823		12,707
	Twelve Months Ended March 31, 2001	103,874		32,704		8,609		41,904

Sammy C. Prough	Twelve Months Ended December 31, 2002	88,259		—		32,306		33,567
Vice President and Chief	Nine Months Ended December 31, 2001	63,931		25,000		7,618		9,820
Operating Officer	Twelve Months Ended March 31, 2001	82,688		19,000		6,770		13,620

Lee D. Atkins (c) Senior Vice President, Chief Financial Officer and Treasurer	Twelve Months Ended December 31, 2002	182,000		—		2,264		17,484

Ronald W. Lyon (d) Vice President, General Counsel and Secretary	Twelve Months Ended December 31, 2002	—		—		—		184,000		(e)

Celia A. Zinn Vice President, Assistant Secretary/ Treasurer and Controller	Twelve Months Ended December 31, 2002	104,000		—		264		15,206

In October 2001, the Company changed its year end from March 31 to December 31. Therefore, compensation data is presented for the year ended December 31, 2002, the nine-month transition period ended December 31, 2001, and the fiscal year ended March 31, 2001.

(a) The Board of Directors allowed each of the individuals to defer certain bonus amounts for 2001. Pursuant to the Stock for Compensation Plan of the Company, the Compensation Committee allowed the individuals to convert a portion of the previously deferred amounts into common stock at a discount, with such discount being a nonrecurring item. The value of the discount on the stock was $82,948, $32,845, $25,000, and $2,000 for Messrs. Pruitt, North, Prough and Atkins, respectively. Although the amounts have been accrued, there have been no distributions or payments made to date.

(b) Amounts for the year ended December 31, 2002, include: $18,752, $13,860, $5,250, $11,032 and $3,000 for Messrs. Pruitt, North, Atkins, Prough and Ms. Zinn, respectively, for Company contributions to the 401(k) plan; $5,113, $3,485, $2,234, $2,535 and $2,206 for premiums paid on term life insurance for Messrs. Pruitt, North, Atkins, Prough and Ms. Zinn, respectively; $12,000 contribution to a deferred compensation account for Mr. Lyon; and $95,003, $49,001, $20,000, $10,000, $10,000 and $10,000 representing the value of shares received under our Stock for Compensation Plan in lieu of cash compensation by Messrs. Pruitt, North, Prough, Atkins, Lyon and Ms. Zinn, respectively. The individuals deferred receipt of the shares pursuant to the plan. Although the amounts have been accrued, there have been no distributions or payments made to date.

(d) Mr. Lyon became an executive officer in October 2001.

(e) Mr. Lyon’s employment contract with the Company as retained general counsel has terms pursuant to which he provides for his own administrative support and maintenance of his separate office facilities. See “Certain Relationships and Related Transactions” for a description of the arrangement.

Compensation Committee Report

The Compensation Committee of the Board of Directors (the “Committee”), which is composed of three non-employee directors, administers the executive compensation programs of the Company. The Committee reviews and approves all issues pertaining to executive compensation. The objective of the Company’s compensation programs is to provide compensation that enables the Company to attract, motivate and retain talented and dedicated executives, foster a team orientation toward the achievement of business objectives, and directly link the success of our executives with that of our shareholders. The Committee held four meetings during 2002.

The Company extends participation in its incentive programs to certain key employees, in addition to executive officers, based on their potential to contribute to increasing shareholder value. The Company intends to expand incentive programs to all regular employees of the Company in the future.

In structuring the Company’s compensation plans, the Committee takes into consideration Section 162(m) of the Internal Revenue Code (which disallows the deduction of compensation in excess of $1 million except for certain payments based upon performance goals) and other factors the Committee deems appropriate. As a result, if compensation in excess of $1 million is paid under the Company’s compensation plans, a portion may not be deductible under Section 162(m).

• Base Salary Compensation

A base salary range is established for each executive position to reflect the potential contribution of each position to the achievement of the Company’s business objectives and to be competitive with the base salaries paid for comparable positions in the national market by similar companies. The Committee utilized industry information for compensation purposes. In addition, the Committee considers information about other companies with which the Committee believes the Company competes for executives, but which are not part of such industry information.

Within the established base salary ranges, actual base salary is determined by the Company’s performance in relation to attainment of specific goals, and a subjective assessment of each executive’s achievement of individual objectives and managerial effectiveness. The Committee annually reviews the performance of the Co-Chairman of the Board, President and Chief Executive Officer and receives reports on other executive officers whose performances are reviewed by the Chief Executive Officer. The Committee, after consideration of the Company’s financial performance and such other subjective factors as the Committee deems appropriate for the period being reviewed, establishes the base compensation of such officers.

In reviewing the annual achievement of each executive and setting the new base annual salary levels for 2002, the Committee considered each individual’s contribution toward meeting the board-approved budgeted financial plan for the previous year, customer satisfaction, compliance with the Company’s capital financial plan, the individual’s management effectiveness and the individual’s base compensation compared to the national market.

• Annual Incentive Compensation

All executive officers are eligible for annual incentive compensation.

The primary form of annual incentive compensation is the Company’s Annual Incentive Plan for employees selected by the Committee, including the executive officers, which have an opportunity to directly and substantially contribute to the Company’s achievement of short-term objectives. Annual incentives are structured so that potential compensation is based upon evaluation of the CEO by the Board of Directors and the accomplishment of goals set during the year and the CEO’s evaluation of selected employees which include the named executive officers.

Changes in annual incentive compensation to the executive officers in 2002 compared to 2001 resulted from an

individual’s relative attainment of his or her goals, the achievement of certain performance standards for business units over which an executive officer had responsibility, and the Company achieving certain financial, performance and other goals.

For 2002, Mr. Pruitt was eligible for an annual short-term incentive target of up to 30% of base salary. Other participants were eligible for annual short-term incentive payments as determined by the CEO. The annual incentive for selected employees and executive officers was tied to the attainment of individual goals and management skills. The balance was based upon the Company’s achievement of goals that are established annually. Mr. Pruitt’s annual incentive compensation was determined to be $56,002. The annual incentive compensation for the named executive officers was determined to be $10,000 for Mr. North, $20,000 for Mr. Prough, $10,000 for Mr. Atkins, $10,000 for Mr. Lyon, and $10,000 for Ms. Zinn. All executive officers, including the CEO, have elected to receive the annual incentive compensation in the form of common stock of the Company. Although the amounts have been accrued, there have been no distributions or payments in the form of common stock to date.

• Achievement Based Compensation

In October 1992, the Cooperative entered into an Achievement Based Contract-Southwestern Public Service Company (“ABC-SPS Contract”) with David W. Pruitt, Ulen North and two former employees. In accordance with the terms of the ABC-SPS Contract, the compensation distributed to the individuals equals 2% of the annual net purchased power cost savings derived from the SPS purchased power contract compared to the prior Texas Utilities purchased power contract and the power supply agreements for the Hunt-Collin Division. The compensation is computed as of the end of each calendar year based on an assessment of the estimated savings and is approved by the Compensation Committee. The ABC-SPS Contract, which has been assumed by the Company, expires in October 2003. For the year ended March 31, 2001, $124,000 was paid pursuant to the Contract. For the year ended December 31, 2002, and the nine months ended December 31, 2001, compensation attributable to the contract was approximately $156,000 and $48,000, which amounts have not been paid, but are shown as a liability on the balance sheet.

In June 1999, the Cooperative entered into an Achievement Based Compensation Contract-Merger or Acquisition With Other Electric Utilities (“ABC-Merger Contract”) with the named executives, certain other officers, and its directors and advisory directors, a total of 16 individuals. The ABC-Merger Contract was amended in 2000. In accordance with the terms of the ABC-Merger Contract, the participants receive compensation equal to 1.5% of the total assets added to the Cooperative or the Company by merger or acquisition since 1990. Total assets added means only those mergers or acquisitions of electric or telephone cooperatives or municipal electric systems that require only the assumption of debt and equity. Amounts paid under the ABC-Merger Contract are allocated 60% to participating executive officers, 10% is allocated to the general counsel and 30% is allocated to directors and advisory directors. The ABC-Merger Contract, which has been assumed by the Company, expires in August 2010. No amounts have been paid or accrued under the ABC-Merger Contract for the year ended December 31, 2002, nine months ended December 31, 2001, or the year ended March 31, 2001.

In August 2001, the Cooperative entered into an Achievement Based Compensation Contract-Power Transmission Contract (“ABC-Power Transmission Contract”) involving its executive officers, including the named executives, directors and a former director. The Company has assumed the ABC-Power Transmission Contract. In accordance with the terms of the ABC-Power Transmission Contract, the participants will receive compensation equal to 1.0% of the net profit or net capital acquired by the Cooperative or Company in connection with the sale or leaseback of the transmission system if payment is taken in cash or 2.0% if payment is taken in stock of the Company. Payment will be deferred until the earlier of 2003 or new equity is raised by the Company in the amount of $5 million or more. Amounts paid under the ABC-Power Transmission Contract are allocated 60% to the executive officers and the remaining 40% is allocated equally to each of the directors and the former director. No amounts have been paid or accrued under the Power Transmission Contract.

• Stock Based Compensation

Stock incentive compensation is offered to employees who are in positions that can affect the Company’s long-term success through the formation and execution of its business strategies. Stock incentive compensation is made under the Company’s Stock Incentive Plan (the “SIP”). The SIP also allows grants to all full-time regular employees of the

Company selected by the Committee. The SIP has been established to advance the interests of the Company and its shareholders by providing a means to attract, retain and motivate employees, directors and consultants upon whose judgment, initiative and effort the Company’s continued success, growth and development is dependent. The purposes of stock incentive compensation are to: (1) focus key employees’ efforts on performance which will increase the value of the Company to its shareholders; (2) align the interests of management with those of the Company’s shareholders; (3) provide a competitive long term incentive opportunity; (4) provide a retention incentive for key employees; and (5) provide a method to reduce the Company’s short term cash needs.

Under the SIP, awards are provided to such participants, and in such amounts, as the Committee deems appropriate. The number and form of awards vary on the basis of position and pay level. The level of total compensation for similar positions in companies considered comparable by the Committee is used as a reference in establishing the level of awards.

For the year ended December 31, 2002, directors received an aggregate of 3,000 shares under the SIP pursuant to the standard arrangement for compensation of directors.

In June 2002, the Committee adopted a Stock for Compensation Plan that allows the Company’s officers, including the named executive officers, directors and other key employees selected by the Compensation Committee to elect to receive cash compensation in the form of common stock. The Board believes that the Stock for Compensation Plan will promote the interests of the Company and its shareholders by assisting the Company in attracting, retaining and stimulating the performance of employees and directors, and by aligning their interests through ownership of common stock with interests of shareholders, and provide a method for the Company to reduce short term cash requirements. As part of its review of 2002 compensation, the Compensation Committee allowed certain officers and directors of the Company, including the individuals named in the compensation table, to convert a portion of the 2001 cash bonus previously deferred by the individuals into shares of common stock at a discount on the date of valuation. The discounts are reflected in the compensation table above.

In the event of a change in control, such stock based incentives or compensation may accelerate and vest, and restrictions or performance criteria lapse. No shares have been granted under these plans.

• Chief Executive Officer

Mr. Pruitt’s base salary and his annual short-term incentive compensation are established annually. In recommending the base salary to be effective in 2002, while not utilizing any specific performance formula and without ranking the relative importance of each factor, the Committee took into account relevant salary information in the national market and the Committee’s subjective evaluation of Mr. Pruitt’s overall management effectiveness in his position as Co-Chairman of the Board, President and Chief Executive Officer of the Company and his achievement of individual goals. Factors considered included his continuing leadership of the Company and his contribution to strategic direction, management of change in an increasingly competitive environment, management of operations, and the overall productivity of the Company. Mr. Pruitt’s base salary was $215,000 in 2002. In addition, pursuant to the terms of the Stock for Compensation Plan, the Compensation Committee allowed Mr. Pruitt to convert previously deferred cash compensation into shares of common stock at a discount. The discount is reflected in the compensation table above.

Based upon the above factors, Mr. Pruitt’s 2002 short term incentive compensation was set at $56,002. Mr. Pruitt will also receive $78,002 under the Achievement Based Contracts for 2002. Mr. Pruitt elected to receive shares of common stock under the Company’s Stock for Compensation Plan in lieu of these cash bonuses, which have not been distributed or paid to date.

	The Compensation Committee

	Sammie D. Buchanan, Chairman
	Floyd L. Ritchey

Executive Officer Employment Contracts

The Company has entered into employment contracts, which contain change in control provisions, with the executive officers. The agreements are intended to insure the officers’ continued service and dedication to the Company and to ensure their objectivity in considering, on the Company’s behalf, any transaction that would result in a change in control of us. The material terms of those contracts are as follow:

David W. Pruitt’s contract commenced in August 1992 and is for an initial term of 10 years. Unless a written notice to terminate the contract at the end of the initial term is given at least 360 days prior to the eighth anniversary of the initial term, the contract term is automatically extended for a three-year term from the eighth anniversary date. Thereafter, unless a written notice to terminate the contract is given 90 days prior to any subsequent anniversary date, the contract automatically extends for an additional three-year term. The contract can be terminated earlier for good cause, as defined in the contract, which includes dishonesty and neglect by Mr. Pruitt of his job duties. There is also a provision in Mr. Pruitt’s contract that if his job responsibility and authority are limited, changed or eliminated or if he is required to move from the Midland, Texas, area, he will be paid for the remainder of the term of his contract. Mr. Pruitt’s contract has been extended to August 2005. If there is a change in control and the contract terminates, Mr. Pruitt will receive an amount equal to six times the sum of his annual base salary and the greater of the highest bonus awarded to him in a prior year or 50% of his annual base salary. The contract also has provisions for healthcare coverage similar to that of a retiree, reimbursement of any tax or tax payments Mr. Pruitt may be required to make for any excise tax imposed under Section 4999 of the Internal Revenue Code, and reimbursement of any taxes resulting from the excise tax reimbursement.

Other officers, including the named executives, have contracts with initial terms of one to two years. Unless a written notice to terminate is given prior to an anniversary date of the contract, they automatically renew for a one to two year term. The contracts can be terminated earlier if the Chief Executive Officer determines that the officer is not properly performing the duties of his or her job or for cause, as defined in the contract, which includes dishonesty and neglect by the officer of his job duties. If the contract is terminated for any other reason, other than a change of control, the officer will receive an amount equal to his or her current salary and benefits for a period of one to two years. If there is a change of control and the contract terminates, the officer will receive an amount equal to six times the sum of his or her annual base salary and the greater of the highest bonus awarded to him or her in a prior year or 50% of his or her annual base salary. The contracts also have provisions for healthcare coverage similar to that of a retiree, reimbursement of any tax or tax payments the officer may be required to make for any excise tax imposed under Section 4999 of the Internal Revenue Code, and reimbursement of any taxes resulting from the excise tax reimbursement.

In the event of a termination by the Company other than for cause, stock based incentives or compensation may accelerate and vest, and restrictions or performance criteria may lapse.

Performance Graph

The following graph shows a one year comparison, prepared in accordance with the rules of the Securities and Exchange Commission, of cumulative total shareholders’ returns for our common stock, the S&P 500 Index and the S&P Utilities Index. The Company’s stock began trading on the American Stock Exchange on March 14, 2002, therefore, the graph represents data beginning in March 2002 for Cap Rock Energy Corporation with a complete 12 months data being provided for S&P 500 and S&P Utilities.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Other than as set forth in the following table, we know of no other beneficial owner of more than five percent of our outstanding common stock. The information provided is as of March 28, 2003.

Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership	Percent of Class

Cap Rock Energy Corporation Shareholders’ Trust 115 S. Travis Sherman, TX 75090	341,882 shares of Common Stock	26.3%

(1) As reported in Schedule 13D filed with the Securities and Exchange Commission on October 3, 2002. Trustees of the Trust are Alfred J. Schwartz and Robert G. Holman, who have shared power to vote and dispose of the shares, pursuant to certain provisions in the Trust document. See also Item 13. Certain Relationships and Related Transactions.

The following table sets forth certain information regarding the beneficial ownership of our common stock as of March 28, 2003, by each of our directors and named executive officers, and by all of our directors and executive officers as a group. Except as otherwise indicated below, each of the persons named in the table have sole voting and investment power with respect to the shares beneficially owned by such person as set forth opposite such person’s name:

Name of beneficial owner	Amount and Nature of Beneficial Ownership (1)		Percent of Class (2)

Directors
Sammie D. Buchanan	1,710		—
Russell E. Jones	2,514		—
Floyd L. Ritchey	1,434		—
Michael D. Schaffner	1,533		—
Newell W. Tate	2,956		—

Executive Officers
David W. Pruitt	31,788	(3)	2.4	%
Ulen A. North, Jr.	11,538		—
Sammy C. Prough	7,100	(3)	—
Lee D. Atkins	1,200		—
Ronald W. Lyon	1,010		—
Celia A. Zinn	1,000		—

All Directors and Executive Officers as a group (11 individuals)	63,783		4.7	%(4)

(1) Includes restricted share units deferred under the Company’s Stock for Compensation Plan and deferred director awards under the Stock Incentive Plan as follows: Buchanan, 1,351; Jones, 787; Ritchey, 1,351; Schaffner, 1,351; Tate, 1,351; Pruitt, 26,088; North, 11,468; Prough, 7,000; Atkins, 1,200; Lyon, 1,000 and Zinn, 1,000 respectively.

(2) No director or executive officer owns any of our equity securities other than our common stock. Percentages are omitted if the person owns less than one percent of the outstanding shares of common stock calculated in accordance with the rules of the Securities and Exchange Commission.

(3) Includes 5,700 shares for Mr. Pruitt and 100 shares for Mr. Prough purchased by those individuals in open market transactions at market price.

(4) Includes deferred shares referred to in item (1) above.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

One of the Company’s executive officers, Ronald W. Lyon, has an employment contract as retained general counsel with the Company, but is not considered an employee under Federal labor laws. Mr. Lyon is paid a monthly retainer fee of $13,500 which is meant to cover the cost of maintaining his office, including administrative support, rent and other overhead expenses, as well as any salary he may draw. In addition, the Company contributes $1,000 per month to a deferred compensation plan for Mr. Lyon. The Company also reimburses Mr. Lyon for direct out-of-pocket expenses he may incur on the Company’s behalf, such as for travel, meals and meeting fees.

As shown in Item 12. Security Ownership of Certain Beneficial Owners and Management, the Cap Rock Energy Corporation Shareholders’ Trust holds more than 5% of the outstanding shares of the Company. The Trust was established by the Company on behalf of former members of the Cooperative whose current addresses are unknown and would have received stock in connection with the conversion of the Cooperative into the Company. The shared authority of the two Trustees of the Trust is to make distribution of stock to beneficial owners when they have been located. Other powers are limited to those granted in the Trust document, the Share Option Agreement and the Funding Agreement.

tender offer or other repurchase offer. If the tender offer by the Company has a premium of 25% or more, the Trustees shall sell all of the shares at the highest cash price offered. In addition, the Trustees shall not vote the shares in favor of a sale or pledge of assets of the Company, nor for any change in the capital structure or powers of the Company or in connection with a merger or dissolution, unless previously approved by the Company’s Board of Directors.

The Funding Agreement between the Trust and the Company provides that the Trustees may request funds from the Company to pay for compensation and expenses of the Trustees in connection with their duties and responsibilities as Trustees of the Trust. In the event the Company fails to fulfill its obligations under the Funding Agreement, the Trustees may sell such shares as are necessary for the Trust to pay such compensation and expenses. The Company transferred less than $1,000 in 2002 to the Trust to pay for the Trustees’ costs and expenses.

The Option Agreement grants the Company the right to acquire all of the shares that would otherwise escheat to the State of Texas as the average market price of the shares for 30 trading days before the Company exercises its option.

ITEM 14. CONTROLS AND PROCEDURES

Within the 90-day period prior to the date of this report, an evaluation was carried out, under the supervision and with the participation of management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective, subject to the limitations below, to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

There have been no significant changes in the Company’s internal controls or in other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

The Company, including its CEO and CFO, does not expect that the Company’s disclosure and internal controls and procedures will prevent or detect all error and all fraud. A control system, no matter how well conceived or operated, can provide only reasonably, not absolute, assurance that the objectives of a control system are met.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8K

Financial Statements

For a list of the consolidated financial statements filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page F-1.

Financial Statement Schedule

The following financial statement schedules are included in Item 14: Schedule II - Valuation and Qualifying Accounts for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001.

Reports on Form 8-K

During the quarter ended December 31, 2002, the Company filed Form 8-K:

Reporting on October 8, 2002, that the Company had scheduled its annual meeting of shareholders for December 2, 2002, and its record date for voting at the annual meeting as October 17, 2002.

Reporting on October 22, 2002, that the Company received a letter on behalf of the Board of Directors of Lamar Electric Cooperative Association, which stated that they intended to terminate the Combination Agreement.

Reporting as of November 1, 2002, that the Company had obtained a signed commitment from its major lender, National Rural Utilities Cooperative Finance Corporation, to refinance its $28 million line of credit.

Reporting on November 5, 2002, that the Company learned that on October 30, 2002, Lamar Electric Cooperative Association had filed a lawsuit seeking a declaratory judgment in order to terminate the Agreement to Combine without any obligation to reimburse the Company for the costs and expenses it incurred in attempting to complete the combination.

Reporting that the Company received notification on November 14, 2002, from the attorney representing Lamar Electric Cooperative Association that Lamar terminated the Management Service Agreement between Lamar and the Company.

Exhibits

Exhibit No.		Item
Exhibit 3.1		Articles of Incorporation of the Company and amendments thereto(1)
Exhibit 3.2		Bylaws of the Company(1)
Exhibit 3.3		Restated and Amended Articles of Incorporation of the Cooperative(1)
Exhibit 3.4		Bylaws of the Cooperative(1)
Exhibit 3.5		Amended and Restated Bylaws of the Company(1)
Exhibit 3.6		Amended and Restated Articles of Incorporation of the Company(1)
Exhibit 3.7		Articles of Amendment to the Amended and Restated Articles of Incorporation of the Company(1)
Exhibit 3.8		Amended and Restated Bylaws of the Company(1)
Exhibit 5.1		Opinion of Ronald W. Lyon(1)
Exhibit 8.1		Tax Opinion of Looper Reed & McGraw, a Professional Corporation(1)
Exhibit 10.1		Second Amendment to Transaction Documents dated November 9, 1994, between Southwestern Public Service Company, the Cooperative, et. al.(1)
Exhibit 10.2		Restated Mortgage and Security Agreement dated September 21, 1988, made by and between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.3		Second Restated Mortgage and Security Agreement dated October 24, 1995, made by and between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.4		Loan Agreement dated October, 1995, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.5		First Amendment to Loan Agreement dated as of October 28, 1997, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.6		Loan Agreement dated as of June 22, 2000, between the Cooperative and National Rural Utilities Cooperative Finance Corporation and amendment.(1)
Exhibit 10.7		Loan Agreement dated December 13, 1994, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.8		Loan Agreement dated March 30, 1993 between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.9		Loan Agreement dated March 10, 1992, TX 107-A-9025, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.10		Loan Agreement dated May 17, 1990, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.11		Loan Agreement dated March 22, 1990 between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.12		Notice of Meeting and Proxy Statement for Special Meeting held October 20, 1998(1)
Exhibit 10.13		Commitment letter dated as of February 11, 2000 between National Cooperative Services Corporation and Cap Rock Energy Corporation for credit facilities associated with the purchase of certain electric assets owned by Citizens Utilities Company(1)
Exhibit 10.14		Loan Agreement dated March 10, 1992, TX 107-A-9026, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.17		Power Sale Agreement dated May 1, 1999, between the Cooperative and Electric Clearinghouse, Inc.(1)
Exhibit 10.18		Wholesale Power Supply and Services Contract dated April 16, 1997 Between Texas New Mexico Power Company and the Cooperative(1)
Exhibit 10.19		Southwestern Public Service Company Wholesale Full Requirements Service Rate Schedule and related Agreement, as amended, with the Cooperative(1)
Exhibit 10.20		Ordinance of the City of Greenville, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity(1)
Exhibit 10.21		Ordinance of the City of Midland, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity(1)
Exhibit 10.22		Ordinance of the City of Stanton, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity(1)
Exhibit 10.23		Employment Contract between the Cooperative and Ulen North(1)
Exhibit 10.24		Employment Contract between the Cooperative and David W. Pruitt(1)

Exhibit No.		Item
Exhibit 10.25		Achievement Based Compensation Agreement of the Cooperative dated August 28, 1994(1)
Exhibit 10.26		Achievement Based Compensation Agreement of the Cooperative dated October 27, 1992(1)
Exhibit 10.27		The Cooperatives Supplemental Executive Deferred Compensation Retirement Plan(1)
Exhibit 10.28		Cap Rock Energy Corporation 2001 Stock Incentive Plan(1)
Exhibit 10.29		Cap Rock Energy Corporation 2001 Employee Stock Purchase Plan(1)
Exhibit 10.30		Form of Equity & Membership Redemption Options(1)
Exhibit 10.31		Form of Equity Redemption Options(1)
Exhibit 10.32		Agreement for Purchase and Sale dated February 7, 2000, by and among Walter Mickelson, et al., Multimedia Development Corporation and New West Resources, Inc.(1)
Exhibit 10.33		Stock Acquisition Agreement dated January 1, 2001, between Thomas E. Kelly, Richard C. Skillern, Johnny D. Grimes, Billy D. Grimes and New West Resources, Inc.(1)
Exhibit 10.34		Consolidating Loan Agreement dated March 30, 1993 between Cap Rock Electric Cooperative, Inc. and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.35		Integrated Supply Agreement between Cap Rock Electric Cooperative, Inc. and Temple, Inc.(1)
Exhibit 10.36		Employment Contract between the Cooperative and Mickey Sims(1)
Exhibit 10.37		Amendment to Line of Credit Agreement dated June 27, 1997 between National Rural Utilities Cooperative Finance Corporation and the Cooperative(1)
Exhibit 10.38		Loan Agreement dated March 10, 1992, TX 107-A-9027, between the Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.39		Achievement Based Compensation Contract of the Cooperative dated August 22, 2000(1)
Exhibit 10.40		Loan Agreement dated March 10, 1992, TX 107-A-9024, between Cooperative and National Rural Utilities Cooperative Finance Corporation(1)
Exhibit 10.41		Wholesale Power Agreement dated June 25, 1977, between Lower Colorado River Authority and McCulloch Electric Cooperative, Inc.(1)
Exhibit 10.42		Amendment to Wholesale Power Agreement dated September 28, 1987 between Lower Colorado River Authority and McCulloch Electric Cooperative, Inc.(1)
Exhibit 10.43		Director Compensation Plan of the Company(1)
Exhibit 10.44		Trust Agreement for the Cooperative Supplemental Executive Deferred Compensation Retirement Plan(1)
Exhibit 10.45		CFC Secured Revolving Line of Credit Agreement dated June 24, 1997(1)
Exhibit 10.46		Achievement Based Compensation Agreement of the Cooperative dated June 29, 1999(1)
Exhibit 10.47		Agreement to Combine McCulloch and Cap Rock Electric Cooperatives dated June 30, 1999(1)
Exhibit 10.48		Management Service Agreement between Cooperative and Lamar Electric Cooperative Association(1)
Exhibit 10.49		Notice of Annual Meeting and Proxy Statement for Members of McCulloch Electric Cooperative held on August 21, 1999(1)
Exhibit 10.50		Agreement to Combine Lamar and Cap Rock Electric Cooperatives dated October 28, 1999(1)
Exhibit 10.51		Loan Agreement between NewWest Resources, Inc, Cap Rock Electric Cooperative, Inc. and Bank United Texas FSB dated July 12, 2000(1)
Exhibit 10.52		Unconditional Guaranty from Cap Rock Electric Cooperative to Bank United Texas FSB dated July 12, 2000(1)
Exhibit 10.53		Lamar County Electric Cooperative Association Notice of Special Meeting and Proxy Statement for Special Meeting held December 14, 1999(1)
Exhibit 10.54		Signature Leasing, Inc. Master Lease Agreement dated April 1, 2000(1)
Exhibit 10.55		Personal Services Agreement between Leonard S. Herring and the Cooperative dated December 16, 1999(1)
Exhibit 10.56		Term Loan Agreement between Eddins-Walcher Company, Frank’s Fuels, United Fuel & Energy Corporation, and NewWest Resources dated July 12, 2000(1)
Exhibit 10.57		NewCorp Resources Electric Cooperative Open Access Transmission Tariff(1)
Exhibit 10.58		Supplement to the Restated Mortgage and Security Agreement between the Cooperative and CFC dated May 17, 1990(1)
Exhibit 10.59		Loan Agreement between Cap Rock Cooperative Finance Corporation and CFC dated June 22, 1999(1)
Exhibit 10.60		Confirmation Letter between Electric Clearinghouse, Inc. and the Cooperative dated May 27, 1999(1)
Exhibit 10.61		Service Agreement Rate Schedule WP between NewCorp Resources and Cap Rock Electric Cooperative dated March 31, 1995(1)

Exhibit No.		Item
Exhibit 10.62		Transaction Agreement dated as of September 9, 1993 between Southwestern Public Service Company, the Cooperative and OTP, Inc.(1)
Exhibit 10.63		Assignment of Certificate of Convenience and Necessity by the Cooperative to NewCorp Resources dated January 17, 1996(1)
Exhibit 10.64		Supplemental Agreement between NewCorp Resources and the Cooperative dated April 25, 1995(1)
Exhibit 10.65		Third Amendment to Transaction Documents by and among Southwestern Public Service Company, the Cooperative, NewCorp Resources et al dated March 3, 1995(1)
Exhibit 10.66		Assignment of Wholesale Power Contract from the Cooperative to NewCorp Resources dated March 3, 1995(1)
Exhibit 10.67		QSE and Ancillary Services Agreement between the Cooperative and Garland Power and Light dated June 1, 2001(1)
Exhibit 10.68		Letter of Intent between the Company and Boeing Capital Corporation dated June 5, 2001(1)
Exhibit 10.69		Employment Contract between the Company and Lee D. Atkins(1)
Exhibit 10.70		Employment Contract between the Company and Ronald W. Lyon(1)
Exhibit 10.71		Employment Contract between the Company and Sam Prough(1)
Exhibit 10.72		Achievement Based Compensation Agreement of the Cooperative dated August 21, 2001(1)
Exhibit 10.73		Letter from State Securities Board of the State of Texas dated December 6, 2001(1)
Exhibit 10.74		Employment Contract between the Company and Celia A. Zinn (2)
Exhibit 10.75		Cap Rock Energy Corporation Shareholders’ Trust (2)
Exhibit 10.76		Cap Rock Energy Corporation Trust Share Option Agreement(2)
Exhibit 10.77		Cap Rock Energy Corporation Trust Funding Agreement(2)
Exhibit 10.78		Supplemental Executive Deferred Compensation Retirement Plan(2)
Exhibit 20.1		Election Form(1)
Exhibit 21.1		Subsidiaries of the Company(1)
Exhibit 23.2		Consent of Ronald W. Lyon is contained in his opinion filed as Exhibit 5.1 to this registration statement.(1)
Exhibit 23.4		Consent of Looper Reed & McGraw(1)
Exhibit 99.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of David W. Pruitt(2)
Exhibit 99.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 of Lee D. Atkins(2)

(1) Previously filed

(2) Filed herewith

SIGNATURES

In accordance with the requirements of the Securities Act of 1934, as amended, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing Form 10K and authorizes this 10K to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, Texas on April 10, 2003.

	CAP ROCK ENERGY CORPORATION

	By:	/s/ David W. Pruitt
	David W. Pruitt
	Co-Chairman of The Board, President And
	Chief 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 dates indicated.

Signature	Title	Date

/s/ David W. Pruitt	Co-Chairman of the Board, President and Chief	April 10, 2003
David W. Pruitt	Executive Officer

*	Senior Vice President, Chief Financial Officer	April 10, 2003
/s/ Lee D. Atkins	and Treasurer

*	Co-Chairman of the Board	April 10, 2003
/s/ Russell E. Jones

*	Director	April 10, 2003
/s/ S. D. Buchanan

*	Director	April 10, 2003
/s/ Floyd L. Ritchey

*	Director	April 10, 2003
/s/ Michael D. Schaffner

*	Director	April 10, 2003
/s/ Newell W. Tate

CERTIFICATION

I, David W. Pruitt, certify that:

1. I have reviewed this annual report on Form 10-K of Cap Rock Energy Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: April 10, 2003

	By: /s/ David W. Pruitt
	David W. Pruitt
	Co-Chairman of the Board, President and Chief Executive Officer

CERTIFICATION

I, Lee D. Atkins, certify that:

1. I have reviewed this annual report on Form 10-K of Cap Rock Energy Corporation;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (or persons performing the equivalent function):

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: April 10, 2003

	By: /s/ Lee D. Atkins
	Lee D. Atkins
	Senior Vice President, Chief Financial Officers and Treasurer

CAP ROCK ENERGY CORPORATION
SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS
ALLOWANCE FOR DOUBTFUL ACCOUNTS
AMOUNTS STATED IN THOUSANDS

COLUMN A - DESCRIPTION	COLUMN B - BALANCE AT BEGINNING OF PERIOD		COLUMN C - CHARGED TO COSTS AND EXPENSES		COLUMN D - DEDUCTION - CHARGED - OFF		COLUMN E - BALANCE AT END OF PERIOD
December 31, 2002	$	202	$	113	$	265	$	50
December 31, 2001	$	292	$	107	$	197	$	202
March 31, 2001	$	202	$	228	$	138	$	292

INDEX TO FINANCIAL STATEMENTS

Independent Auditors’ Report, KPMG LLP

Report of Independent Public Accountants, Arthur Andersen LLP

Consolidated Statements of Operations
Year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001

Consolidated Balance Sheets
December 31, 2002, and 2001

Consolidated Statement of Equity
Year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001

Consolidated Statements of Cash Flows
Year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001

Notes to Consolidated Financial Statements

F-1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of
Cap Rock Energy Corporation:

We have audited the 2002 financial statements of Cap Rock Energy Corporation and subsidiaries (the Company) as listed in the accompanying index. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The 2001 and 2000 financial statements of Cap Rock Energy Corporation, as listed in the accompanying index, were audited by other auditors who have ceased operations and whose report, dated March 29, 2002, expressed an unqualified opinion on those financial statements. That report of other auditors refers to a change in accounting principles related to accounting for derivative financial instruments.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cap Rock Energy Corporation as of December 31, 2002, and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The Valuation and Qualifying Accounts, Schedule II is presented for purposes of additional analysis and is not a required part of the basic financial statements. This information has been subjected to the auditing procedures applied in our audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.

	KPMG LLP


Midland, Texas
March 28, 2003

F-2

This is a copy of the report previously issued by Arthur Andersen LLP. The report has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP provided a consent to the inclusion of its report in this annual report on Form 10-K.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of

Cap Rock Electric Cooperative, Inc.:

We have audited the accompanying consolidated balance sheets of Cap Rock Electric Cooperative, Inc. and subsidiaries (the “Cooperative”) as of December 31, 2001, and March 31, 2001, and the related consolidated statements of operations, changes in equities and margins and cash flows for the nine months ended December 31, 2001, and each of the two years in the period ended March 31, 2001. These financial statements and the schedule referred to below are the responsibility of the Cooperative’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the 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 the Cooperative as of December 31, 2001, and March 31, 2001, and the results of its operations and its cash flows for the nine months ended December 31, 2001, and each of the two years in the period ended March 31, 2001, in conformity with accounting principles generally accepted in the United States.

As explained in Note 1. to the consolidated financial statements, effective April 1, 2001, the Cooperative adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

	Arthur Andersen LLP


Dallas, Texas
March 29, 2002

F-3

CAP ROCK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	YEAR ENDED DECEMBER 31, 2002			NINE MONTHS ENDED DECEMBER 31, 2001			YEAR ENDED MARCH 31, 2001
	Successor			Predecessor			Predecessor
	- - - (Thousands of dollars except per share amounts) - - -

Operating Revenues:
Electric sales	$	73,335		$	52,326		$		70,742
Gas sales and royalty income	—			—			486
Other	1,302			796			1,237
Total operating revenues	74,637			53,122			72,465
Operating Expenses:
Purchased power	36,433			28,194			44,967
Operations and maintenance	7,327			5,828			6,961
Administrative and general	7,144			3,326			4,180
Depreciation and amortization	6,134			4,568			6,171
Property taxes	1,367			997			1,408
Write off of investment in Citizens (Note 6)	—			—			2,815
Write off of investment in MDC (Note 7)	—			—			1,063
Impairment of Lamar combination costs (Note 5)	1,357			—			—
Other	202			229			579
Total operating expenses	59,964			43,142			68,144
Operating Income	14,673			9,980			4,321
Other Income (Expense):
Allocation of income from associated organizations	478			1,205			823
Interest expense, net of capitalized interest	(7,103		)	(8,004		)	(11,832			)
Interest and other income	1,027			1,161			1,411
Equity earnings in MAP (Notes 9 and 24)	115			88			127
Total other income (expense)	(5,483		)	(5,550		)	(9,471			)
Income (Loss) before income taxes	9,190			4,430			(5,150			)
Income tax expense	414			—			—
Income (loss) before extraordinary item	8,776			4,430			(5,150			)
Extraordinary gain on early extinguishment of debt (Note 13)	—			—			969
Net Income (Loss)	$	8,776		$	4,430		$		(4,181	)
Pro forma Basic and Diluted Earnings Per Share (Unaudited):
Income (loss) from continuing operations				$	3.40		$	(3.95		)
Extraordinary item				—			0.74
Net income (loss) per share				$	3.40		$	(3.21		)
Pro forma shares outstanding				1,302,355			1,302,355
Basic and Diluted Earnings Per Share:
Net income	$	6.74
Number of common shares used in computing earnings per share	1,302,355

The accompanying notes are an integral part of these consolidated financial statements.

F-4

CAP ROCK ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	DECEMBER 31,
	2002		2001
	Successor		Predecessor
	(Thousands of dollars)

ASSETS
Current Assets:
Cash	$	9,899	$	5,498
Accounts receivable:
Electric sales, net	4,723		3,642
Other	337		497
Current portion of notes receivable (Note 9 and 15)	12,490		1,000
Purchased power subject to recovery	3,501		—
Other current assets (Note 8)	7,805		1,419
Total current assets	38,755		12,056

Utility plant, net (Note 10)	157,323		164,547
Investments and notes receivable (Note 9)	12,490		25,904
Nonutility property, net (Note 11)	1,564		1,623
Other assets (Note 12)	1,162		10,329
Total Assets	$	211,294	$	214,459

LIABILITIES AND EQUITY

Current Liabilities:
Current portion of long-term debt	$	33,924	$	9,131
Accounts payable:
Purchased power	3,381		3,057
Other	1,805		3,165
Equity redemption credits (Note 2)	732		827
Purchased power cost subject to refund	—		387
Accrued and other current liabilities (Note 18)	3,054		3,167
Current income tax payable (Note 27)	414		—
Total current liabilities	43,310		19,734

Long-Term Debt, Net of Current Portion:
Mortgage notes (Note 13)	147,744		123,414
Line of credit (Note 13)	—		28,000
Capital lease - transmission system (Note 14)	—		17,632
Note payable and other capital leases (Note 15)	308		12,686
Total long-term debt	148,052		181,732

Deferred Credits (Note 20)	5,194		5,321

Stockholders’ Equity:
Common stock, par value $.01 per share, 50,000,000 shares authorized, 1,302,355 shares issued and outstanding	13		—
Preferred stock, par value $1 per share, 50,000,000 shares authorized, no shares issued or outstanding	—		—
Paid in capital	5,949		—
Retained earnings	8,776		—
Total stockholders’ equity	14,738		—

Equities and Margins	—		7,672
Total Liabilities and Equity	$	211,294	$	214,459

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CAP ROCK ENERGY CORPORATION

CONSOLIDATED STATEMENT OF EQUITY

	(Thousands of dollars except number of shares)
	Successor													Predecessor
				Paid in Capital				Retained Earnings		Total Stockholders’ Equity				Patronage Capital Credits				Other Equities and Margins				Patronage Capital Obligated to be converted to Shareholder Equity				Total Margins and Equities

	Common Stock
	# shares	Value
Balance, March 31, 2000															$	18,502			$	(5,843	)						$	12,659
Net loss															—				(4,181		)						(4,181		)
Patronage capital credits retired for electric credits															(2,401		)		—								(2,401		)
Patronage capital credits retired for cash															(621		)		219								(402		)
Balance, March 31, 2001															15,480				(9,805		)						5,675
Net income for nine months															—				4,430								4,430
Patronage capital credits retired for electric credits															(909		)		—								(909		)
Patronage capital credits retired for cash															(2,181		)		657								(1,524		)
Patronage capital obligated to be converted into shareholder equity (Note 2)															(12,390		)		—				12,390				—
Balance, December 31, 2001															—				(4,718		)		12,390				7,672
Issuance of the Company’s common stock to the Cooperative in	1,302,355	$	13		$	(13	)				$	—
exchange for its net assets and liabilities					(4,718		)				(4,718		)						4,718								4,718
Conversion costs					(1,685		)				(1,685		)
Distribution by the Cooperative of shares of the Company’s common stock to the Cooperative’s members					12,390						12,390												(12,390		)		(12,390		)
Payments to former Cooperative members for fractional shares and other redemption equity					(25		)				(25		)
Net income									8,776		8,776
Balance December 31, 2002	1,302,355	$	13		5,949				8,776		$	14,738			$	—			$	—			$	—			$	—

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CAP ROCK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

	YEAR ENDED DECEMBER 31, 2002			NINE MONTHS ENDED DECEMBER 31, 2001			YEAR ENDED MARCH 31, 2001
	Successor			Predecessor			Predecessor
	- - - - - - - - - -- - - (Thousands of dollars)- - - - - - - - - - - - -
Cash Flows From Operating Activities:
Net income (loss)	$	8,776		$	4,430		$	(4,181	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	9,253			8,328			10,863
Write off of investments in proposed acquisitions	1,357			—			1,326
Equity earnings in Map	(115		)	(88		)	(127		)
Gain on extinguishment of debt	—			—			(969		)
Change in:
Other assets/deferred credits	5,909			17			(2,251		)
Accounts receivable	(921		)	2,370			(2,491		)
Purchased power cost subject to refund	(3,888		)	(3,808		)	1,649
Other current assets	(6,386		)	(926		)	(40		)
Accounts payable and accrued expenses	(735		)	934			3,180
Other	—			—			63
Net cash provided by operating activities	13,250			11,257			7,022

Cash Flows From Investing Activities
Utility plant additions, net	(1,517		)	(4,257		)	(9,714		)
Proceeds from liquidation of investments, net of additions	1,043			(76		)	(360		)
Issuance of notes receivable	—			—			(16,500		)
Collection of notes receivable	1,000			2,100			733
Restricted cash investment	—			—			1,900
Other	—			—			527
Net cash provided by (used in) investing activities	526			(2,233		)	(23,414		)

Cash Flows From Financing Activities:
Net borrowings under lines of credit	—			40			1,781
Proceeds from mortgage notes	—			—			21,027
Proceeds from other long-term debt and capital leases	534			—			15,000
Payments on mortgage notes	(3,034		)	(2,320		)	(8,310		)
Payments on other long-term debt and capital leases	(6,387		)	(4,377		)	(5,128		)
Retirement of member equity	(488		)	(2,605		)	(3,773		)
Net cash provided by (used in) financing activities	(9,375		)	(9,262		)	20,597

Increase (Decrease) in Cash and Cash Equivalents:	4,401			(238		)	4,205
Cash at beginning of period	5,498			5,736			1,531
Cash at end of period	$	9,899		$	5,498		$	5,736

Supplemental Cash Flow Information
Cash paid during the period for interest	$	8,611		$	8,320		$	11,778

The accompanying notes are an integral part of these consolidated financial statements.

F-7

CAP ROCK ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2002 AND 2001, AND MARCH 31, 2001

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cap Rock Energy Corporation, Inc. (the “Company” and the “Successor”) was formed in December 1998 in accordance with a conversion plan to reorganize a member owned electric cooperative, Cap Rock Electric Cooperative, Inc. (the “Cooperative” or the “Predecessor”) to a shareholder owned business corporation. The Company assumed the business of the Cooperative, which was incorporated as an electric cooperative in the State of Texas in 1939 to provide electric distribution and power to its members. The Company provides service to over 35,000 meters in 28 counties in Texas. Its customers are located in the Midland-Stanton area of West Texas, the Central Texas area around Brady, and in Northeast Texas in Hunt, Collin and Fannin Counties. The Company, through its subsidiaries, also has transmission assets and is engaged in providing various electric services to customers, as well as miscellaneous non-electric services.

Presentation and Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company, Cap Rock Energy Corporation (Energy) and its wholly-owned subsidiaries, NewCorp Resources Electric Cooperative, Inc. (“NewCorp”), Cap Rock Cooperative Finance Corporation (“CRCFC”), Capstar Communications and the Cooperative. The financial statements presented for the periods ending on or before December 31, 2001, are the historical consolidated financial statements of the Cooperative, and the consolidated financial statements for periods ending after January 1, 2002, are those of the Successor, Cap Rock Energy Corporation. The Predecessor’s consolidated financial statements include the accounts of the Cooperative and its wholly-owned subsidiaries, Cap Rock Energy Corporation, Capstar Resources, Inc. (“Capstar”), Capstar Communications, Cap Rock Utilities, Inc. (“Cap Rock Utilities”), New West Resources, Inc. (“New West”), CRCFC and NewCorp.

Effective June 30, 2001, Capstar, Cap Rock Utilities and New West were merged into NewCorp.

All significant intercompany accounts and transactions have been eliminated in consolidation. Unless otherwise indicated, all references to the Company will include any and all activities of its Predecessor.

Basis of Accounting

The Company’s accounting records, and those of the Predecessor, are maintained in accordance with the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (“FERC”) for Class A and B electric utilities. The Company’s accounting policies, and those of the Predecessor, conform to generally accepted accounting principles as applied in the case of regulated public utilities in the United States and are in accordance with the accounting requirements and ratemaking practices of FERC. Because the rates charged by the Company are regulated by its Board of Directors and certain other regulators, the Company prepares its financial statements in accordance with the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulations.” SFAS No. 71 requires a cost based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. In certain circumstances, SFAS No. 71 requires that certain costs and/or obligations be reflected in a deferral account on the balance sheet and not reflected in the statement of income or loss until matching revenues are recognized. It is the Company’s policy to assess the recoverability of costs recognized as regulatory assets and the Company’s ability to continue to account for its activities in accordance with SFAS No. 71, based on each regulatory action and the criteria set forth in SFAS No. 71.

Regulatory assets and liabilities are those assets and liabilities recognized under SFAS No. 71 only by a regulated entity. At December 31, 2002, the Company had one regulatory liability and one regulatory asset. The regulatory asset was a power cost recovery receivable of $3.5 million and the regulatory liability was deferred revenue of $2.2 million. At December 31 2001, the Company had one regulatory asset and two regulatory liabilities. The regulatory asset was a fuel price derivative of $482,000 and the regulatory liabilities were deferred revenue of $1.3 million and power cost subject to refund of $387,000.

F-8

Change in Year End

During the quarter ended December 31, 2001, the Board of Directors of the Cooperative adopted a resolution changing the date of the Cooperative’s and its subsidiaries’ fiscal year-end from March 31 to December 31, effective December 31, 2001. For comparative purposes, unaudited statements of operations for the nine months ended December 31, 2000, and year ended December 31, 2001, has been included for the Predecessor as shown in Note 4.

Pro Forma Earnings Per Share (Unaudited)

Pro forma basic and diluted earnings (loss) per share (unaudited) are presented in the accompanying consolidated statements of operations for the nine months ended December 31, 2001, and the year ended March 31, 2001. Pro forma basic and diluted earnings per share are based on the assumption that the Cooperative was converted from a member owned cooperative to a shareholder owned business corporation and 1,302,355 shares of common stock were issued for members’ ownership interests on April 1, 2001 and 2000. As discussed in Note 2, such conversion occurred in February 2002.

Earnings Per Share

The Company’s basic and diluted earnings per share (“EPS”) have been calculated in accordance with SFAS No. 128, “Earnings Per Share.” Basic and diluted EPS for the year ended December 31, 2002, are not materially different. Basic EPS is based on the weighted-average number of common shares outstanding. Diluted EPS is based on the weighed-average number of common shares outstanding and common stock equivalents which would arise from the exercise of stock options. There are no potentially dilutive common stock equivalents outstanding.

As of March 28, 2003, there were 59,000 shares of common stock that had been tendered pursuant to the Company’s repurchase offer. See Note 16.

Use of Estimates

The preparation of the Company’s consolidated financial statements, in conformity with accounting principles generally accepted in the United States, requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents. The carrying amount of cash equivalents approximates market value due to the short-term maturity of these investments.

Allowance for Doubtful Accounts

The Company provides an allowance for doubtful accounts receivable that are estimated to be uncollectible based on historical trends for each rate class. As of December 31, 2002 and 2001, the allowance for doubtful accounts was $50,000 and $202,000, respectively. Bad debt expense for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, was $120,000, $102,000 and $228,000 respectively.

Investments in Associated Organizations

Investments in associated organizations relate primarily to required membership certificates and the accumulated capital of National Rural Utilities Cooperative Finance Corporation (“CFC”) and Texas Electric Cooperative, Inc. (“TEC”). Investments in these associated organizations are accounted for using the cost method of accounting because the Company’s investment is less than 20% of the total equity capital of either organization. CFC and TEC capital allocations

F-9

are determined annually by the respective organizations based on their bylaws, operating margins and other factors. The Company recognizes equity allocations, and income, from the associated organizations when declared by the organizations. For the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, allocation of income from associated organizations was $478,000, $1,205,000 and $823,000, respectively. CFC is the Company’s primary lender and TEC provides various lobby services for electric cooperatives in Texas.

Investments and Notes Receivable

The Company normally accounts for its investments under the cost basis method of accounting if the investment is less than 20% of the voting stock of the investee, or under the equity method of accounting if the investment is greater than 20% of the voting stock of the investee.

The Company previously had investments in oil and gas royalty interests. As discussed in Note 9, effective December 1, 2000, the Company transferred its oil and gas royalty interests in exchange for shares of common stock of Map Resources, Inc. (“MAP”). Since December 1, 2000, the Company has accounted for its investment in MAP under the equity method of accounting.

Utility Plant

Utility plant is stated at the original cost of construction, including the cost of contracted services, direct labor, materials and similar overhead items. The cost of maintenance, repairs and minor replacements are charged to operations as incurred. Gains or losses resulting from retirements or other dispositions of utility property in the normal course of business are credited or charged to the accumulated provision for depreciation. The Company does not accrue any cost for major maintenance or repair projects.

Contributions in aid of construction are credited to the applicable utility plant accounts.

Depreciation is provided on a straight line basis over estimated useful lives of the assets as follows:

Transmission plant		10 - 33 years
Distribution plant		32 years
General plant:
Structure and improvements		40 years
Transportation		6 - 8 years
Computer equipment		5 - 7 years
Other		16 - 21 years

Nonutility Property

Nonutility property is stated at original cost. Maintenance, repairs and miscellaneous replacement and renewals of nonutility property are charged to operations as incurred. The majority of depreciation is provided on a straight line basis over estimated useful lives, which range from 15 to 30 years.

Income and expenses related to the Company’s primary real estate property are recognized on an accrual basis. Income from the Company’s miscellaneous real estate partnership investments is recognized as income is received. Income recorded for each period shown has been $12,000 or less.

Goodwill and Intangible Assets

Prior to the implementation of SFAS No. 142, “Goodwill and Other Intangible Assets,” amortization of goodwill was computed on a straight-line basis over a 60-month period. The Company adopted SFAS No. 142 beginning January 2002 and therefore assessed its goodwill for impairment at that date, and at December 31, 2002. In accordance with this pronouncement, the Company reviews its goodwill and intangible assets with indefinite lives on an annual basis and makes a determination as to whether an impairment has occurred. In reviewing goodwill, management compares the imputed fair value of the goodwill to its recorded carrying value. Evaluation of fair value takes into

F-10

consideration various factors such as number of meters, economic growth of a geographical area, diversity in the customer base and power suppliers and their mix of fuel costs. No impairment has been necessary because the fair value of goodwill exceeded the carrying value.

Separate intangible assets that are not deemed to have indefinite lives will continue to be amortized over their estimated useful lives, which range from 3 to 10 years.

Deferred Revenue

Deferred revenues are included in Deferred credits on the balance sheet (see Note 20), and represent power costs expensed in prior periods that will be billed to customers and recognized as revenue over the next 12 months.

Capitalized Interest

The Company capitalizes, to construction work in progress, interest cost calculated in accordance with SFAS No. 34, “Capitalization of Interest Cost.”

Equities and Margins

The Cooperative’s equities and margins consisted of patronage capital credits, patronage capital obligated to be converted into shareholder equity, and other equities and margin accounts for the periods before the conversion. According to the Cooperative’s Bylaws, only the Cooperative’s operating profits could be allocated to the members’ equity accounts. Operating losses and nonoperating gains and losses were recorded as other equities and margins and not allocated to members’ equity accounts. Subsidiary gains and losses were recorded as other equities and margins.

For the nine months ended December 31, 2001, and the year ended March 31, 2001, in accordance with the Cooperative’s conversion plan, the Cooperative repurchased certain members’ equity account balances aggregating approximately $2,181,000 and $621,000, respectively, at a discounted cash price of $1,524,000 and $402,000, respectively. The difference was credited to the Cooperative’s other equity accounts. As of December 31, 2001, the equity retirement payable had been fully paid. As of March 31, 2001, the Cooperative’s equity retirement payable balance was $411,000. As of December 31, 2001, $12,390,000 was reclassified from Patronage Capital to Patronage Capital Obligated to be Converted into Shareholder Equity, with the subsequent issuance of the Successor’s common stock in the first quarter of 2002.

For the nine months ended December 31, 2001, and the year ended March 31, 2001, in accordance with the Cooperative’s conversion plan, the Cooperative repurchased certain members’ patronage capital credit balances aggregating $909,000 and $2,401,000, respectively, by issuing electric credits of the same respective amounts to be ratably applied to the members’ electric bills over a 24-month period. As of December 31, 2002 and 2001, the balance of the equity redemption credits was $732,000 and $1,195,000, respectively.

Revenue Recognition

For all periods through the end of 2002, the Company and its predecessor, the Cooperative, utilized the cycle billing method to recognize revenue, pursuant to the rate-making policy as set by the Board of Directors. The cycle billing method recognizes revenue on an “as billed basis” which recognizes revenue when the customer is billed and not on an accrual basis, which recognizes revenue as the power is distributed to the customer. Had the Company/Cooperative recorded an accrual, a regulatory liability would have existed because the entities were not entitled to recognize revenue until the customers had been billed. In the utility industry, the rate-making policy defines the accounting requirements according to SFAS No. 71.

F-11

recognize revenue. Under the new rate-making structure, the Company will accrue revenue and recognize revenue when power is distributed to the customer.

Unrecognized, unbilled electric revenues as of December 31, 2002 and 2001, were approximately $2,521,000 and $2,076,000.

Late-payment fees are accrued into income after the passage of the due-date for customers. Only the current month’s billed revenue is subjected to a one-time 5% late-payment penalty.

Revenues from gas sales and royalty income were accrued monthly based on estimated sales. Other revenue consists primarily of building rental income and is accrued monthly based on contractual lease obligations.

Purchased Power Costs

The Company accrues its purchased power cost based on actual usage through the end of each month.

The Company’s tariffs for electric service include power cost recovery clauses under which electric rates charged to customers are adjusted to reflect actual power costs incurred. In September 2001, the Company determined that approximately $1,700,000 of collected power recovery costs subject to refund represented billable costs incurred and as a result, recorded an adjustment to reduce purchased power costs and the purchased power subject to refund account. This amount was reflected in the power recovery costs subject to refund liability. January 2002, the Company determined that approximately $4,360,000 inclusive of the $1,700,000 described above, of power costs incurred and expensed in periods prior to 2002 were recoverable costs. These costs were approved by the Board to be recovered through billings to customers over a 24 month period beginning in January of 2002 and ending in December 2003. See Note 20. As of December 31, 2002, the Company’s purchased power cost subject to recovery was $3,501,000, and at December 31, 2001, purchased power subject to refund was $387,000.

Stock Based Compensation

The Company accounts for its employee stock incentive plan using the intrinsic method in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees, and as amended by SFAS No. 123, "Accounting for Stock-Based Compensation." If compensation cost had been determined in accordance with SFAS No. 123, the Company's net income and earnings per share on a pro-forma basis for 2002 would not have been different from the Company's reported results of operations or earnings per share. See also Note 19.

Federal Income Taxes

The Company accounts for federal 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.

The Cooperative and NewCorp are tax-exempt organizations under Internal Revenue Code Section 501(c)(12). Energy and Capstar are taxable organizations for Internal Revenue Service purposes and file a consolidated federal income tax return. CRCFC is a taxable organization for Internal Revenue Service purposes and files a separate federal income tax return. For the nine months ended December 31, 2001, and the year ended March 31, 2000, Energy, Capstar and New West incurred no tax liability.

Upon conversion to a shareholder owned business corporation, the activities and transactions formerly performed by the Cooperative became taxable. The pro forma results of the Cooperative, assuming it was taxable, would not have been materially different, due to net operating loss carryforwards available to reduce tax expense for the nine months ended December 31, 2001, and year ended March 31, 2001.

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Derivative Instruments

The Company uses derivative instruments to manage the natural gas component of power costs, which minimizes the fluctuations in customers’ power bills. All payments made or received in connection with these type of transactions will be collected from or rebated to the customers through the power cost recovery component of the customers’ power bills. The fair market value of these instruments is recorded as an asset or liability with a corresponding regulatory liability or regulatory asset, as all amounts paid or received will be passed through to the Company’s customers.

New Accounting Standards

On August 15, 2001, the FASB issued SFAS No. 143, “Asset Retirement Obligations.” SFAS No. 143 addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is required to be adopted for fiscal years beginning after June 14, 2002. The Company anticipates that the adoption of SFAS No. 143 will not have an effect on its results of operations or financial position.

In November 2002, the FASB issued FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). FIN 45 requires a guarantor to recognize a liability, at the inception of the guarantee, for the fair value of obligations it has undertaken in issuing the guarantee and also include more detailed disclosures with respect to guarantees. FIN 45 is effective for guarantees issued or modified after December 31, 2002, and requires the additional disclosures for interim or annual periods ended after December 15, 2002. The Company does not expect that the provisions of FIN 45 will have a material impact on its results of operations or financial position.

In January 2003, the FASB issued FASB Interpretation No.46, “Consolidation of Variable Interest Entities — an interpretation of ARB No. 51” (“FIN 46”). FIN 46 requires that if an entity has a controlling financial interest in a variable interest entity, the assets, liabilities and results of activities of the variable interest entity should be included in the consolidated financial statements of the entity. FIN 46 provisions are effective immediately for all arrangements entered into after January 31, 2003. For those arrangements entered into prior to January 31, 2003, the FIN 46 provisions are required to be adopted at the beginning of the first interim or annual period beginning after June 15, 2003. The Company does not expect that the provisions of FIN 46 will have a material impact on the Company’s results of operations or financial position.

In December, 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation, Transition and Disclosure” (SFAS No. 148), an amendment of FASB Statement No. 123. SFAS No. 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company utilizes the intrinsic method. The Company believes that SFAS No. 148 will have no impact on its results of operations or financial position.

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Other Comprehensive Income

There were no items of comprehensive income for any period presented.

Reclassifications

Certain reclassifications have been made to prior periods’ financial statements to conform to the presentation adopted in the current period.

2. CORPORATE RESTRUCTURING

On October 20, 1998, the Cooperative’s members adopted a conversion plan to reorganize the Cooperative from a member owned electric cooperative to a shareholder owned business corporation. The conversion plan granted broad powers to the Cooperative’s Board of Directors, without further action of the membership, to engage in all transactions necessary to implement the conversion plan. Such powers include, among other things, the ability to form and capitalize new entities, transfer and/or sell assets, and purchase interests of the members and holders of Cooperative’s equity accounts.

In connection with the conversion plan, Cap Rock Energy Corporation was formed in December 1998 as a subsidiary of the Cooperative and substantially all of the Cooperative’s operational activities were transferred to Energy. Under the conversion plan, the Cooperative was to continue in existence and was to continue to provide electricity to its members until such time as the Board of Directors, at its option and without further approval or action of its members, elected to take one of the actions authorized therein. The Board elected to transfer all of the assets and liabilities to Energy, in exchange for common stock of Energy, to distribute such stock to the Cooperative’s members and holders of equity accounts and ultimately to liquidate and dissolve the Cooperative.

Energy has registered shares of its common stock with the Securities and Exchange Commission as of February 8, 2002, and they were distributed to the Cooperative’s members and holders of equity accounts that chose that option. On March 14, 2002, the common stock of Energy was approved for listing on the American Stock Exchange. See Note 16 concerning the Company’s repurchase offer.

Energy’s Articles of Incorporation provide that any shareholder or affiliate of a shareholder holding in excess of 5% of Energy’s outstanding common stock will have its voting rights for those shares in excess of 5% reduced to 1/100 per share.

Pursuant to the conversion plan, during the nine months ended December 31, 2001, and the year ended March 31, 2001, the Cooperative retired equity accounts aggregating $3,090,000 and $3,022,000, respectively, through the Cooperative’s conversion “Dutch Auction” process and its rescission offer.

All Cooperative members with equity accounts greater than $10 received notices from the Cooperative regarding their equity account balances and the “Dutch auction” and electric credit process as outlined in the conversion plan. All Dutch auction bids of 70% or less of stated capital credit account balances received from members were accepted by the Cooperative. For the nine months ended December 31, 2001, and the year ended March 31, 2001, equity accounts of $2,181,000 and $621,000, respectively, were retired for a discounted Dutch auction cash price of $1,524,000 and $402,000, respectively. The difference was credited to the Cooperative’s other equity account. As of December 31, 2001, the equity retirement payable had been fully paid. As of March 31, 2001, the Cooperative’s equity retirement payable balance was $411,000. As of December 31, 2001, $12,390,000 was reclassified from Patronage Capital to Patronage Capital Obligated to be Converted to Shareholder Equity, with the subsequent issuance of Energy common stock in the first quarter of 2002.

For the nine months ended December 31, 2001, and the year ended March 31, 2001, Cooperative members opting to receive electric credits equal to 100% of their equity account balances totaled $909,000 and $2,401,000 respectively. Equity redemption electric credits of less than $240 were applied immediately and credits of over $240 are being ratably applied over a 24-month period to those former members’ electric bills. The unamortized balance of equity redemption credits as of December 31, 2002 and 2001, was $732,000 and $1,195,000, respectively.

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3. PRO-FORMA CONSOLIDATED FINANCIAL DATA (UNAUDITED)

The unaudited pro-forma consolidated balance sheet as of December 31, 2001, shows the conversion of the Cooperative’s equities and margins converted into 1,302,355 shares of common stock of Energy.

	(IN THOUSANDS)
	HISTORICAL		ADJUSTMENTS			PRO FORMA
ASSETS
Current assets	$	12,056	$	—		$	12,056
Utility and nonutility property	166,170		—			166,170
Investments and notes receivable	25,904		—			25,904
Other assets	10,329		(1,570		)(A)	8,759
	$	214,459	$	(1,570	)	$	212,889
LIABILITIES AND EQUITIES
Current liabilities	$	19,734	—			$	19,734
Long-term debt	181,732		—			181,732
Deferred credits	5,321		—			5,321
Equities and margins	7,672		(7,672		)(B)	—
Shareholders’ equity:
Common stock, $.01 par value, 50,000,000 shares authorized, 1,302,355 shares issued and outstanding	—		13		(B)	13
Additional paid in capital	—		(1,570		)(A)	6,089
			7,659		(B)
Retained earnings	—		—			—
	$	214,459	$	(1,570	)	$	212,889

The following are pro forma adjustments to the accompanying pro forma consolidated financial data:

(A) To reclassify deferred stock conversion costs to additional paid in capital.

(B) To record 1,302,355 shares of common stock issued and to reclassify other equities and margins to shareholders’ equity.

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4. COMPARABLE STATEMENTS OF OPERATIONS (UNAUDITED)

The following unaudited condensed consolidated statements of operations are presented in addition to the consolidated statements of operations in order to present comparable periods (in thousands):

	YEAR ENDED DECEMBER 31, 2001			NINE MONTHS ENDED DECEMBER 31, 2000
	PREDECESSOR			PREDECESSOR

Total operating revenues	$	73,412		$	52,100

Purchased power	40,781			32,379
Operations and maintenance	7,427			5,484
General and administrative	4,664			2,559
Depreciation and amortization	6,159			4,340
Property taxes	1,380			1,024
Write off of investments	—			3,878
Other	310			437
Total operating expenses	60,721			50,101
Operating income	12,691			1,999

Interest expense	(10,818		)	(7,903		)
Other income items	2,961			1,019
Net income (loss) before extraordinary item	4,834			(4,885		)
Extraordinary item	—			969

Net income (loss)	$	4,834		$	(3,916	)

5. PROPOSED LAMAR ACQUISITION

In October 1999, the Cooperative entered into an agreement (“Combination Agreement”) with Lamar County Electric Cooperative Association (“Lamar”), pursuant to which Lamar was to combine with, and become an operating division of, the Cooperative. The members of Lamar subsequently approved this Combination Agreement. The agreement provided that if the combination was terminated by Lamar, with certain specific allowable exceptions, Lamar was required to reimburse the Cooperative for all costs and expenses it had incurred, whether paid to outside parties or incurred internally, with respect to the combination.

The completion of the combination was delayed because of litigation with Lamar’s power supplier. The power supplier claimed that Lamar and the Cooperative had each breached various agreements.

On August 29, 2000, the Cooperative and Lamar entered into a five year Management Service Agreement. Under the terms of that agreement, Lamar’s Board of Directors continued to set policy and perform all of its fiduciary responsibilities, and the Cooperative performed certain management services for Lamar. As compensation for its management services, the Cooperative (subsequently the Company) received $1,000 per month plus reimbursed costs and expenses. One of the terms of the agreement provided that if Lamar terminated the agreement prior to the expiration of the original term, Lamar would be required to pay a cancellation fee of $300,000 as liquidated damages.

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Lamar terminated the Combination Agreement in October 2002 and the Management Service Agreement in November 2002. The Company believes that Lamar’s stated reason for termination of the Combination Agreement does not fall within the specific allowable exceptions set forth in the agreement, and therefore the Company believes it is entitled to reimbursement of all costs and expenses incurred. The Company is also seeking the specified liquidated damages fee of $300,000 in connection with the termination of the Management Service Agreement.

Because Lamar terminated the Combination Agreement, generally accepted accounting principles required the impairment of costs previously capitalized that were incurred in connection with the combination. At December 31, 2002, these costs, mainly outside legal and consulting fees, aggregated $1,357,000 have been expensed and are shown on the consolidated statement of operations. At December 31, 2001, these costs aggregated approximately $956,000 and are shown on the consolidated balance sheet in Other assets. See Note 12.

6. PROPOSED CITIZENS ACQUISITION

In February 2000, the Cooperative and Citizens Communications Company, formerly Citizens Utilities Company (“Citizens”), a publicly-owned utility corporation, entered into Purchase and Sale Agreements (the “Agreements”) for Citizens’ electric utility businesses in Arizona and Vermont for a total of $287 million.

Although the Cooperative was able to obtain a financing commitment for approximately $191 million for the Arizona acquisition, it was unable to secure financing on acceptable terms and conditions for the balance of the purchase price due in large part to the unprecedented increase in Arizona’s wholesale power costs and the inability to recover such increased costs quickly from ratepayers.

On March 7, 2001, the Cooperative and Citizens agreed to terminate the Agreements and the Cooperative wrote off $2,815,000 of deferred acquisition costs related to the terminated Citizens acquisition, including termination costs of $1,100,000.

7. PROPOSED MDC ACQUISITION

In February 2000, the Cooperative executed an agreement to acquire all of the stock of Multimedia Development Corporation (“MDC”), a wireless telecommunication entity with operations in New Mexico, for $12,500,000, subject to certain working capital adjustments.

Although the Cooperative was successful in securing financing for part of the purchase price, it was unable to secure adequate financing for the acquisition on acceptable terms and conditions. Accordingly, for the year ended March 31, 2001, the Cooperative wrote off $1,063,000 related to the terminated MDC acquisition.

8. OTHER CURRENT ASSETS

Other current assets as of December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002		2001

Capital lease sinking fund (Note 14)	$	7,395	$	—
Derivative contracts at market value	—		898
Prepaid insurance	335		219
Interest receivable	58		31
Other	17		271
Total Other current assets	$	7,805	$	1,419

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At December 31, 2002, the capital lease sinking fund balance of $7,395,000 is shown in Other current assets because the final balloon payment associated with the capital lease for the transmission system is due in 2003. At December 31, 2001, the balance of the capital lease sinking fund was $6,189,000 and was shown in Other assets.

9. INVESTMENTS AND NOTES RECEIVABLE

Investments and notes receivable as of December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002		2001

Investments in associated organizations:
CFC capital term certificates	$	6,304	$	6,393
CFC patronage capital	2,519		2,522
TEC patronage capital and bonds	852		817
Other	73		136
Total investments in associated organizations	9,748		9,868

Investment in United Fuel (Note 15)	360		360
Notes receivable—United Fuel, net of current portion (Note 15)	—		12,667
Investment in MAP	2,162		2,047
Other investments	220		962
Total Investments and notes receivable	$	12,490	$	25,904

The Company previously had investments in oil and gas royalty interests. As discussed in Note 24 to the consolidated financial statements, as of December 1, 2000, the Company transferred all of its oil and gas royalty interests with a net book value of $3,531,000 to MAP, a newly formed company, in exchange for 3,675,000 shares (100%) of MAP’s common stock and a $1,500,000 note receivable. As of December 31, 2000, MAP issued an additional 3,675,000 shares of common stock to Flagstone Petroleum Corporation, a privately owned company, in exchange for oil and gas interests and other properties with an estimated fair market value of $1,553,000. Accordingly, as of March 31, 2001, the Company owned approximately 49% of MAP, with such interest being reduced to 42% at December 31, 2001, upon the exercise of certain stock options and issuance of additional stock. The investment in MAP is accounted for using the equity method of accounting. The Company’s equity earnings in MAP for the year ended December 31, 2002, and the nine months ended December 31, 2001, was $115,000 and $88,000, respectively, and $127,000 for the four months ended March 31, 2001.

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10. UTILITY PLANT

Utility plant as of December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002			2001

Transmission facilities	$	64,757		$	59,824
Distribution facilities	177,892			175,355
General facilities	10,097			12,458
Total Utility plant	252,746			247,637
Less accumulated depreciation	(95,648		)	(85,562		)
Total utility plant in service, net	157,098			162,075
Construction work in progress	225			2,472
Total Utility plant, net	$	157,323		$	164,547

All utility plant assets are pledged to secure debt and capital lease obligations.

As discussed in Note 14, the Company has received various proposals to either refinance the debt associated with the transmission system or sell the transmission system. At December 31, 2002, the transmission system had a net book value of approximately $24,450,000. Any proposed transaction will be subject to several conditions, including:

Approval of the transaction by the Board of Directors and appropriate individuals of the buyer;

• Completion of any due diligence reviews;

• Execution by the parties of a definitive agreement and all other necessary agreements; and

• Approval of regulatory agencies having jurisdiction over the transmission system, if applicable or necessary.

Upon closing, all amounts remaining unpaid with respect to the transmission capital lease obligation will be deducted from the proceeds of any sale.

11. NONUTILITY PROPERTY

Nonutility property as of December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002			2001

Real estate	$	2,257		$	2,257
Furniture, fixtures, and other	7			11
Total Nonutility property	2,264			2,268
Less accumulated depreciation	(700		)	(645		)
Total Nonutility, property net	$	1,564		$	1,623

The Company owns a 50,000 square foot office building that is used as its general corporate headquarters. The Company currently occupies approximately 30% of the building and the remainder is leased to commercial tenants, subject to leasing terms ranging from monthly to 5 years. For the year ended December 31, 2002, nine months ended December 31, 2001 and the year ended March 31, 2001, third party building rental revenue was $286,000, $244,000 and $253,000 respectively. Building rental revenues, which are not material to the Company’s operations, for each of the next

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five years are expected to be approximately $250,000 per year. As of December 31, 2002 and 2001, the net book value of the building and related property was $1,161,000 and $1,219,000, respectively.

The Company has guaranteed debt of certain real estate partnerships, with the maximum exposure of such guarantees aggregating $273,000 at December 31, 2002. The guarantees are over the life of the associated debt of the partnership, and, if called, would require payment by the Company.

12. OTHER ASSETS

Other assets as of December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002		2001
Capital lease sinking fund (Note 14)	$	—	$	6,189
Capital lease acquisition cost, net of amortization (Note 14)	735		1,035
McCulloch goodwill, net of amortization	199		199
Lamar acquisition costs (Note 5)	—		956
Stock conversion costs	—		1,570
Other	228		380
Total Other assets	$	1,162	$	10,329

The stock conversion costs are the direct costs associated with the conversion of the Cooperative into a shareholder owned corporation. These amounts were charged against equity as a reduction to additional paid in capital when the conversion occurred in February 2002.

At December 31, 2002, the capital lease sinking fund is shown in Other current assets because the associated capital lease for the transmission system is due in 2003.

The McCulloch goodwill represents costs incurred in connection with the acquisition of another electric cooperative in 1999, in the amount of $373,000. As of December 31, 2002 and 2001, the accumulated amortization was $174,000.

13. MORTGAGE NOTES AND LINE OF CREDIT

The CFC notes have been issued in conjunction with a Second Restated Mortgage and Security Agreement, dated October 24, 1995 (“Loan Agreement”). Substantially all of the Company’s distribution assets are collateralized in connection with the notes. The notes have maturity dates ranging from 2005 to 2035, with required quarterly payments of principal and interest. Under the Loan Agreement, the Company may elect to pay interest on a fixed or variable interest rate basis, as defined. The existing long-term debt consists of series of loans from CFC that impose various restrictive covenants, including, among other things, provisions that prohibit the incurrence or guaranty of other secured indebtedness and requires the maintenance of a 1.35 debt service coverage ratio, as defined in the CFC Loan Agreements. In addition, the Company may not make any cash distribution or any general cancellation or abatement of charges for electric energy or services to its customers if the ratio of equity to total assets is less than 20%.

In conjunction with the conversion plan, CFC waived the 20% equity to total assets ratio requirement, consented to the distribution of cash and electric credits to former members, waived the 1.35 debt service coverage ratio requirement, and notified the Company that all existing CFC indebtedness may remain in place with CFC after the conversion from a member owned cooperative to a shareholder owned corporation.

In December 2002, the Company elected to convert the interest rates on the majority of the mortgage notes from variable to fixed. These lock-ins of interest rates were done for one, two and three year periods. Substantially all of the

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CFC fixed rate notes are subject to interest rate repricing at the end of various periods, at the Company’s option. Mortgage notes with CFC as of December 31, 2002 and 2001 consisted of the following (in thousands):

	DECEMBER 31,
	2002			2001
Interest at 3.35% with interest repricing in December 2003	$	11,525		$	—
Interest at 4.20% with interest repricing in December 2004	70,519			—
Interest at 4.70% with interest repricing in December 2005	35,189			—
Interest at fixed rates:
6.50%	6,188			—
7.00%	3			—
5.79% weighted average	—			13,323
Interest at variable rate of 3.95%	—			113,135
Interest at variable rate of 3.65%	28,000			—
	151,424			126,458
less current maturities	(3,680		)	(3,044		)
Total mortgage debt, net of current portion	$	147,744		$	123,414

As of December 31, 2001, the Company had a Secured Revolving Line of Credit Agreement with CFC aggregating $28 million, interest payable at CFC prime rate plus 1%, secured by distribution plant assets and renewable annually. As of December 31, 2001, the outstanding balance of the line of credit was $28,000,000 with an interest rate of 5.1%. In October 2002, CFC agreed to convert the $28 million line of credit to a long term mortgage note with quarterly payments of approximately $233,000 based on a 30 year amortization schedule, a final balloon payment in 5 years and deferral of the initial principal payment for one year from the date of closing, which date has not yet been determined. At December 31, 2002, the average interest rate was 3.9%, with interest payments due quarterly. The new financing arrangements are subject to execution of the new loan documents.

As of March 31, 2000, the long-term debt assumed as a part of the McCulloch acquisition had a weighted average interest rate of 4.24%. On May 16, 2000, substantially all of that long-term debt was refinanced resulting in an extraordinary gain from early extinguishment of debt of approximately $969,000 for the year ended March 31, 2001. These loans were paid off with loan proceeds received from CFC.

The Company has capitalized, as a part of utility plant, the cost of borrowed funds used for financing construction. Capitalized interest for the year ended December 31, 2002, the nine months ended December 31, 2001 and the year ended March 31, 2001, was $12,000, $31,000 and $131,000, respectively. The rate used for interest charged to construction is a variable rate equal to the rate on the short-term line of credit with CFC.

Annual maturities of the mortgage notes as of December 31, 2002, are as follows (in thousands):

2003	$	3,680
2004	4,731
2005	8,295
2006	4,553
2007	28,961
Thereafter	101,204

Total mortgage debt	$	151,424

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14. CAPITAL LEASE - TRANSMISSION SYSTEM

In connection with the financing, construction and utilization of its transmission line, the Company entered into agreements with Southwestern Public Service Company (“SPS”), Metropolitan Life Insurance Company (“Met Life”), and John Hancock Leasing Corporation (“John Hancock”). The John Hancock lease was paid in full during the year ended March 31, 2000. The substance of the remaining agreements includes financing arrangements with Met Life and a power transmission arrangement with SPS. These agreements qualify as capital leases with reversionary features and, as a result, the transmission line, substation assets and associated capital lease obligations are reflected in the Company’s consolidated financial statements.

The original cost related to the transmission facility and cost of the ten year capital lease of $59,000,000 and $2,999,000, respectively, are being recovered from customers through power cost billings over a ten-year period. Consistent with this ratemaking treatment, the transmission facilities and cost of capital lease are being amortized over ten years. Principal payments on the transmission system capital lease obligation for the year ended December 31, 2002, the nine months ended December 31, 2001, and the year ended March 31, 2001, were approximately $5,047,000, $3,577,000, and $4,490,000 respectively. The corresponding amortization of property and equipment under the capital lease was credited to accumulated depreciation and amortization accounts for the transmission facilities consistent with ratemaking treatment. Required principal payments of $17,632,000 for the capital lease obligation associated with the transmission system as of December 31, 2002, are all classified as current because the capital lease expires in September 2003.

Interest on the capital lease obligations for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, was approximately $1,443,000, $1,305,000 and $2,020,000, respectively, and is classified as purchased power cost consistent with ratemaking treatment.

The lease payments include an amount for a sinking fund, which will be used to reduce the amount of the final debt payment. As of December 31, 2002 and 2001, the balance of the sinking fund was $7,395,000 and $6,189,000, respectively. See Notes 8 and 12.

The Company has received proposals to either refinance the debt associated with the transmission system or sell the transmission system. At December 31, 2002, the transmission system had a net book value of approximately $24,450,000. This proposed transaction will be subject to several conditions, including:

• Approval of the transaction by the Board of Directors and appropriate individuals of the buyer;

• Completion of any due diligence reviews;

• Execution by the parties of a definitive agreement and all other necessary agreements; and

• Approval of regulatory agencies having jurisdiction over the transmission system, if applicable or necessary.

Upon closing, all amounts remaining unpaid with respect to the transmission capital lease obligation will be deducted from the proceeds of any sale.

15. NOTE PAYABLE AND OTHER CAPITAL LEASES

As of March 31, 2000, the Cooperative agreed to make loans totaling $15 million to two fuel and lubricant subsidiaries of United Fuel and Energy Corporation (“United Fuel”). On July 12, 2000, the Cooperative entered into and guaranteed, with CFC’s permission, a $15 million, three-year loan agreement with a bank. At December 31, 2002, the bank loan balance was $12,490,000 and is shown entirely in Current portion of long-term debt because it is due in 2003. At December 31, 2001, the loan balance was $13,667,000, and is included on the balance sheet in Other notes payable, net of the $1,000,000 current portion. The loan agreement requires monthly payments based on a fifteen-year amortization with interest at Wall Street Journal prime rate plus 1%, with such rates aggregating 5.25% and 5.75% at December 31, 2002 and 2001, respectively.

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Simultaneously, the Cooperative loaned $15 million to United Fuel’s two subsidiaries with terms and conditions substantially identical to the bank loan agreement, interest at Wall Street Journal prime rate plus 1.25%, and secured by United Fuel’s stock and properties, as well as plant and equipment of the United Fuel subsidiaries. The Cooperative has pledged its security as collateral for its bank loan agreement. At December 31, 2002, the United Fuel note receivable balance was $12,490,000, and is shown entirely in Current portion of notes receivable because it is due in 2003. At December 31, 2001, the note receivable balance was $13,667,000, and is included on the balance sheet in Investments and notes receivable, net of the $1,000,000 current portion. See also Note 9. At closing, the Cooperative acquired a 10% interest in United Fuel for $300,000, at a cost of $3,000 per share. In January 2001, the Cooperative acquired an additional 5% net interest in United Fuel from certain selling United Fuel shareholders for $60,000, at a cost of $1,200 per share. In addition, beginning January 1, 2002, as long as United Fuel is indebted to the Company or until January 1, 2010, whichever is earlier, the Company has a right to acquire an additional 10% ownership in United Fuel, exercisable in annual increments of 1%-2% through January 1, 2010 at a price of $1,250 per share, subject to certain adjustments. The Company accounts for its investment in United Fuel using the cost method of accounting. If the Company’s ownership in United Fuel were to exceed 20%, it would be required to use the equity method of accounting.

The Company has current maturities of long-term debt and capital leases of $33,924,000 due in 2003. The Company believes that its cash flow from operations in 2003, cash on hand, including sinking fund balances, and funds provided by the repayment of the United Fuel note receivable will be more than sufficient to fund its 2003 debt repayment obligations. United Fuel is currently in discussions with lenders in order to obtain financing that would provide funds to allow United Fuel to fully repay the Company’s note receivable. If United Fuel is not successful in obtaining financing, the Company has other options available to obtain the funds necessary to satisfy its debt obligations. Also, in the event United Fuel is not successful in obtaining financing, United Fuel, or its shareholders who have provided the Company with personal guarantees of the note receivable, would pay down the note and provide funds to the Company such that the Company would, together with its cash flow from operations, be able to satisfy its debt obligations as they become due in 2003. The Company is also considering, as an alternative, an opportunity to extend the payment date of the note payable to the bank for $12,490,000 for an additional year.

The Company has other miscellaneous capital leases for certain equipment used in operations. Future minimum lease payments are as follows (in thousands):

2003	$	122,000
2004	123,000
2005	111,000
2006	44,000
2007	30,000
Total capital lease obligations	$	430,000

16. REPURCHASE OFFER

Commencing one year from the date of the distribution of the Company's common stock to the former members of the Cooperative in connection with the conversion plan and ending 60 days thereafter, the Company offered to purchase at a price of $10 per share all of its shares of common stock that were distributed in connection with the Plan. The effect of the common stock purchase commitment is unknown because it is based on the number of shareholders who accept the offer. Shares of the Company's common stock were originally distributed to certain former members of the Cooperative who elected to receive shares of stock as payment for their equity and membership interest in the Cooperative. Pursuant to the terms of the conversion plan, the Company made a commitment to purchase those shares, held continuously by the original owners of record until the first anniversary of the distribution of the shares at a price of $10 per share if the Company had sufficient cash available to purchase all shares tendered. As of March 28, 2003, the current market price is greater than the $10 offering price.

On February 5, 2003, the Company filed Schedule TO with the Securities and Exchange Commission, thus commencing the repurchase period, which is set to expire April 30, 2003. In an effort to be inclusive rather than exclusive, the Company made the offer to all shareholders of the Company. The number of shares ultimately accepted by the Company for repurchase will be determined by cash available. If cash is not available, the Company can terminate the offer and return all shares tendered. Because the terms and parameters of the repurchase offer were revised, all amounts originally ascribed have been classified as Paid-in capital. As of March 28, 2003, there were 59,000 shares of common stock that had been tendered pursuant to the Company’s repurchase offer.

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17. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2002 and 2001. SFAS No. 107 defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties.

	DECEMBER 31, 2002				DECEMBER 31, 2001
	BOOK VALUE		FAIR VALUE		BOOK VALUE		FAIR VALUE
Cash and cash equivalents	$	9,899	$	9,899	$	5,498	$	5,498
Mortgage notes	151,424		151,424		126,458		126,458

The book value of cash and cash equivalents approximated fair value because of the short maturity of those instruments. The carrying values of accounts receivable and account payables included in the accompanying consolidated balance sheets approximated market value at December 31, 2002 and 2001. As described in Note 13, the Company has both fixed rate and variable rate notes, but the fair value of the fixed rate mortgage notes are assumed to be the same as the carrying value because the interest rates are reflective of market rates.

18. ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities at December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002		2001
Accrued taxes	$	227	$	19
Accrued interest	479		518
Accrued payroll and employee benefits (Note 19)	1,530		1,035
Accrued other	66		156
Derivative liabilities	—		898
Customer deposits and prepayments	752		541
Total Accrued and other current liabilities	$	3,054	$	3,167

19. EMPLOYEE BENEFIT PLANS

Executive Deferred Compensation Plans

As of December 31, 2001, the Company had an Executive Deferred Compensation Plan whereby management, members of the Board of Directors and certain highly compensated employees could defer a portion of their compensation pursuant to the terms of the plan. Monies invested through the plan could be withdrawn by the respective individuals at any time, subject to applicable tax laws. As of December 31, 2002, the plan was terminated and all amounts were distributed to the respective individuals.

In November 2002, the Board approved a new Executive Deferred Compensation Plan with terms similar to the original plan. The Company may also make contributions to the plan on behalf of the individuals participating in the plan. A participant is 100% vested in contributions he may make to the plan, with Company contributions vesting at 10% per year for the first four years, and 20% per year for the next three years. The Compensation Committee of the Board of Directors administers the plan. No amounts have been deferred through December 31, 2002.

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Stock Incentive Plan

The Company has adopted a Stock Incentive Plan that provides for the granting of options to purchase common stock, awards of common stock, both restricted and unrestricted, and certain related rights to eligible officers, employees and directors of the Company. The plan will continue in effect until December 31, 2013. The Stock Incentive Plan provides for a maximum of 800,000 shares of the Company’s common stock to be used in the granting of options and awards of stock. Shares of common stock used to satisfy such awards will be acquired by the Plan either through open market purchases or through the issuance of additional common stock. For the year ended December 31, 2002, the Company recorded compensation expense of $30,000 in connection with awards of 3,000 shares, these shares have not been issued or distributed.

Employee Stock Purchase Plan

The Company has adopted an Employee Stock Purchase Plan (“ESPP”) that provides its employees with the opportunity to purchase shares of its common stock through accumulated payroll deductions. It is the Company’s intention to have the ESPP qualify as an employee Stock Purchase Plan under Section 423 of the Internal Revenue Code of 1986, as amended. The Employee Stock Purchase Plan provides for a maximum of 150,000 shares. As of December 31, 2002, the ESPP had not been fully implemented, and no shares had been issued.

Stock for Compensation Plan

The Company has adopted a Stock for Compensation Plan (“SCP”) that provides a means for eligible employees and directors to receive shares of the Company’s common stock or restricted share units in lieu of cash compensation. The SCP provides for a maximum of 500,000 shares of the Company’s common stock to be used in conjunction with this plan. Cash bonuses of $522,980 had been earned by individuals, who then were awarded shares of stock in lieu of the cash compensation. These shares have not yet been distributed to the applicable individuals.

Defined Contribution Plan

The Company has a 401(k) plan for employees who meet certain eligibility requirements. The plan permits a specified percentage of an employee’s salary to be voluntarily contributed on a pre-tax basis, with a Company matching feature. Participants may contribute from four to 12 percent of eligible earnings to various self-directed investment funds. The plan provides for Company matching contributions at 2-for-1 for the first four percent of an employee’s contribution, and then 1-for-1 up to a maximum of 12%. Company contributions aggregated $481,000, $331,000 and $474,000 for the year ended December 31, 2002, nine months ended December 31, 2001, and year ended March 31, 2001.

Other Postretirement Benefits

The Company provides continued major medical and life insurance coverage to retired employees and their dependents. The cost to maintain such benefits for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, totaled $858,000, $227,000, and $219,000, respectively.

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The funded status of the plan and the amounts recognized on the balance sheet as of December 31, 2002 and 2001 are as follows (in thousands):

	DECEMBER 31,
	2002			2001
Accumulated Postretirement Benefit Obligation (APBO):
Actives not yet eligible	$	1,985		$	1,651
Actives fully eligible	724			207
Retirees and dependents	4,854			1,444
Total APBO	7,563			3,302
Plan assets at fair value	—			—
Accrued postretirement benefit liability	7,563			3,302
Unrecognized loss from past experience different from that assumed and from changes in assumptions	(4,695		)	(606		)
Accrued postretirement benefit cost	$	2,868		$	2,696

Changes in the accrued postretirement benefit cost for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, are as follows (in thousands):

	DECEMBER 31,						MARCH 31,
	2002			2001			2001
Balance, beginning of period	$	2,696		$	2,629		$	2,539
Net periodic postretirement cost	858			356			339
Contributions	(686		)	(289		)	(249		)
Balance, end of period	$	2,868		$	2,696		$	2,629

Net periodic postretirement benefit costs for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001 are as follow (in thousands):

	DECEMBER 31,				MARCH 31,
	2002		2001		2001
Service cost	$	148	$	128	$	125
Interest cost	471		228		214
Amortization of experience loss	239		—		—
	$	858	$	356	$	339

The assumption used in the calculation of the costs presented above were as follows:

	DECEMBER 31,				MARCH 31,
	2002		2001		2001
Discount rate	7.00	%	7.25	%	7.25	%

Health care cost trend rates: Medical and dental 10% in 2003, grading down 1.0% per year to an ultimate rate of 5% for all years beginning in 2008.

Increasing the assumed healthcare cost trend rates by one percentage point in the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, would increase the APBO $1,310,000, $430,000 and $384,000, respectively, and the aggregate of the service and interest cost components by $130,000, $51,000 and $47,000, respectively.

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No return on plan assets was assumed in the calculation as the Company holds no specified plan assets.

20. DEFERRED CREDITS

Deferred credits at December 31, 2002 and 2001, consisted of the following (in thousands):

	DECEMBER 31,
	2002		2001
Post retirement benefits (Note 19)	$	2,868	$	2,696
Deferred executive compensation (Note 19)	3		828
Long-term equity redemption credits (Note 2)	—		368
Unclaimed member capital credits	68		36
Deferred revenue	2,182		1,252
Other	73		141
Total Deferred credits	$	5,194	$	5,321

Deferred revenue relates to purchased power cost expensed in prior years and not billed to customers. Rates billed in prior periods were Board approved rates. Purchased power from prior periods was not billed to customers until the timing was approved by the Board. Effective January 2002, the Company recorded $4,364,000 in deferred revenue and a corresponding increase to its purchased power cost recovery received related to recoveries of purchased power costs approved by the Board. The deferred revenues are being recovered from customers on a monthly basis over a 24 month period from January of 2002 to December of 2003. During 2002, the Company billed and recognized $2,182,000 of deferred revenue. The balance of deferred revenue at December 31, 2002, is $2,182,000 and will be recognized in 2003.

Unclaimed member capital credits are related to capital credit distribution payments made by the Cooperative to its members prior to 1998 that were returned by the postal service as undeliverable and which the Cooperative, after diligent efforts, has been unable to locate.

21. MAJOR CUSTOMERS AND SUPPLIERS

For the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, the Company and its subsidiaries had no customer that accounted for more than 10% of operating revenues.

The Company has outsourced its materials warehousing function to an outside third party. The terms of the contract provide that the third-party maintain an adequate inventory level of distribution type components, with after hours staffing in case of emergencies. The Company believes that in the event the contract with the third-party should not be renewed, the Company’s operations would not be severely affected because new contracts could be secured at competitive rates.

22. REGULATORY MATTERS

Under the Public Utility Regulatory Act of 1995 (the “Act”), the Cooperative had elected not to operate under the regulatory authority of the Public Utility Commission of Texas. In accordance with the Act, any changes in the Cooperative’s electric rates must be approved by its Board of Directors. See also Note 26.

23. ELECTRIC DEREGULATION

On May 27, 1999, the Texas legislature passed a bill relating to the restructuring of the electric utility industry in Texas. The bill, among other things, froze rates for most of the investor-owned utilities until retail competition began January 1, 2002, then mandated a 6% rate decrease for residential and small commercial customers. Rates will be capped for five years. Municipally owned utilities and cooperatives may elect, but are not required, to offer retail customer choice

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on or after January 1, 2002. The Company is presently regulated as a cooperative. However, the Intervenors in the proceeding for the transfer of the Cooperative’s certified territory to the Company have challenged that status. See Note 26. At the present time, the Board of Directors have elected to opt out of deregulation and delay participation in retail competition until there is more certainty concerning the various aspects.

Under the 1999 law, electric cooperatives electing to participate in customer choice shall have the right to offer electric energy and related services at unregulated prices directly to retail customers who have customer choice without regard to geographical location. Electric cooperatives electing not to participate in customer choice will not be permitted to offer electric energy at unregulated prices directly to retail customers outside its certified retail service area.

24. RELATED PARTY ACTIVITY

As described in Note 9, during the year ended March 31, 2001, New West and its board of directors entered into a series of transactions whereby each contributed mineral interests to MAP, and both New West and its board of directors received stock of MAP, New West received a note receivable from MAP, and the directors received options to purchase additional shares of MAP common stock. On June 19, 2001, all of the Map common stock options were exercised by the directors which reduced New West’s interest in Map from approximately 49% to approximately 42%.

In October 1992, the Cooperative entered into an Achievement Based Contract—Southwestern Public Service Company (“ABC-SPS Contract”) with its executive officers and a former employee, a total of four individuals. In accordance with the terms of the ABC-SPS Contract, the compensation distributed to the individuals equals 2% of the annual net purchased power cost savings derived from the SPS purchased power contract compared to the prior Texas Utilities purchased power contract and the power supply agreements for the Hunt-Collin division. The compensation is computed as of the end of each calendar year based on an assessment of the estimated savings and approved by the Compensation Committee. For the year ended December 31, 2002, and the nine months ended December 31, 2001, compensation attributable to the contract was approximately $156,000 and $48,000, which amounts have not been paid, but are shown as a liability on the consolidated balance sheet. For the year ended March 31, 2001, $124,000 was paid pursuant to the contract. The ABC-SPS Contract, which had been assumed by the Company, will expire in 2003.

In June 1999, the Cooperative entered into an Achievement Based Compensation Contract—Merger or Acquisition With Other Electric Utilities (the “ABC-Merger Contract”) with certain of its executive officers, its general counsel and its directors and advisory directors, a total of 16 individuals. The ABC-Merger Contract was amended in 2000. In accordance with the terms of the ABC-Merger Contract, the participants receive compensation equal to 1.5% of the total assets added to the Cooperative or Energy by merger or acquisition since 1990. Total assets added means only those mergers or acquisitions of electric or telephone cooperatives or municipal electric systems that require only the assumption of debt and equity. Amounts paid under the ABC-Merger Contract are allocated 60% to participating executive officers, 10% is allocated to the general counsel and 30% is allocated to directors and advisory directors. No amounts were accruable under the ABC-Merger Contract for the year ended December 31, 2002, nine months ended December 31, 2001, or for the year ended March 31, 2001. The ABC-Merger Contract, which has been assumed by the Company, expires in August 2010.

In August 2001, the Cooperative entered into an Achievement Based Compensation Contract-Power Transmission Contract (“ABC-Power Transmission Contract”) involving its executive officers, directors and a former director. The Company has assumed the ABC-Power Transmission Contract. In accordance with the terms of the ABC-Power Transmission Contract, the participants will receive compensation equal to 1.0% of the net profit or net capital acquired by the Cooperative or Energy in connection with the sale or leaseback of the transmission system if payment is taken in cash or 2.0% if payment is taken in the form of stock of the Company. Payment will be deferred until the earlier of 2003 or new equity is raised by the Company in the amount of $5 million or more. Amounts paid under the ABC-Power Transmission Contract are allocated 60% to the executive officers and the remaining 40% is allocated equally to each of the directors and the former director. No amounts have been paid or accrued under the ABC-Power Transmission Contract.

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25. OTHER SHAREHOLDER MATTERS

The Cap Rock Energy Corporation Shareholders’ Trust (the “Trust”) was established by the Company in October 2002, on behalf of former members of the Cooperative whose current addresses are unknown and would have received shares of common stock in connection with the conversion of the Cooperative into the Company. The shared authority of the two Trustees of the Trust is to make distribution of stock to beneficial owners when they have been located. As of December 31, 2002, there were 344,171 shares of stock held beneficially by the Trust. Other powers are limited to those granted in the Trust document, the Share Option Agreement and the Funding Agreement.

The Trust provides that in the case of a tender offer or other repurchase offer by the Company for shares of the capital stock of the Company, the Trustees may, in their sole discretion and acting jointly in the best interest of the beneficiaries of the Trust, sell all of the shares held in the Trust to the Company at the highest cash price offered under the tender offer or other repurchase offer. If the tender offer by the Company has a premium of 25% or more, the Trustees shall sell all of the shares at the highest cash price offered. In addition, the Trustees shall not vote the shares in favor of a sale or pledge of assets of the Company, nor for any change in the capital structure or powers of the Company or in connection with a merger or dissolution, unless previously approved by the Company’s Board of Directors.

The Funding Agreement between the Trust and the Company provides that the Trustees may request funds from the Company to pay for compensation and expenses of the Trustees in connection with their duties and responsibilities as Trustees of the Trust. In the event the Company fails to fulfill its obligations under the Funding Agreement, the Trustees may sell such shares as are necessary for the Trust to pay such compensation and expenses. The Company transferred less than $1,000 to the Trust in 2002 to pay for the Trustees’ costs and expenses.

The Share Option Agreement grants the Company the right to acquire all of the shares held by the Trust that would otherwise escheat to the State of Texas. The Trustees must notify the Company of their intent to escheat such shares, and the Company then has the right to purchase those shares at the average market price for 30 trading days before the Company exercises its right under the agreement. The shares would not escheat until 2005.

26. COMMITMENTS AND CONTINGENCIES

The Company purchases all of its electric power pursuant to long-term wholesale electric power contracts with Southwestern Public Service Company (“SPS”), Lower Colorado River Authority (“LCRA”) and Garland Power and Light (“Garland”). SPS, LCRA and Garland contracts expire in 2013, 2016 and 2004, respectively, and account for approximately 72%, 13% and 15%, respectively, of the Company’s electric power purchases. The contracts for power cover kWh usage, kW demand levels, transmission, scheduling and ancillary services along with energy and fuel costs. The Company’s purchased power costs fluctuate primarily with the price of the fuel and usage. Management believes that in the event the contracts are not renewed, the Company’s operations will not be severely affected as new contracts can be secured at competitive rates with other electric power providers.

The Company’s West Texas division is supplied power through a contract with SPS. The SPS contract has no minimum kWh usage requirements, but does have minimum charges for kW demand and transmission services. The Company must pay a minimum of 65% of the prior twelve months highest monthly kW demand usage multiplied by a fixed rate along with their pro-rata share of the fixed transmission costs based on the Company’s prior twelve months usage as a percentage of all SPS usage. The SPS contract allows the Company to purchase all power needed. Energy, kW demand, ancillary services and scheduling charges are based on fixed factors charged against usage. The Company also pays a pro-rata share of SPS’s FERC regulated transmission charges. Fuel costs paid to SPS are based on SPS’s actual cost of fuel used to generate electricity. The SPS contract expires in December 2013.

The LCRA contract covers all power utilized by the Central Texas division of the Company and permits the Company to purchase 100% of the power needed to supply the native load of the division. LCRA charges the Company fixed factors for energy, kW demand and scheduling services applied to our usage. LCRA’s transmission charges are fixed

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monthly charges regulated by the Electric Reliability Council of Texas (“ERCOT”). Fuel costs paid to LCRA are the Company’s pro-rata share of the amounts that LCRA actually pays for fuel to generate electricity. The Company is required to purchase power from LCRA, but has no minimum usage levels and only minimal penalties. The contract between LCRA and the Company expires in June 2016.

Garland provides all power supply requirements, including ancillary and scheduling services, for the Northeast Texas division. The Company is not required to purchase a minimum amount of capacity, and is billed solely on actual usage. The price per kWh is at a fixed rate and does not fluctuate with the price of gas or other fuels.

Various members of ERCOT provide the Northeast Texas division of the Company with transmission services. ERCOT regulates the transmission rates that are charged by the ERCOT members. The Company pays a fixed monthly fee based on the estimated usage submitted prior to the beginning of each year. There is no contract with the individual ERCOT members. Taking power over the ERCOT network requires the Company to pay fees regulated by ERCOT. The annual charges to use the ERCOT transmission network cover the period from January 1 to December 31 of each year. Withdrawing from ERCOT and using other transmission services relieves the user of further charges. Because the use of the network is governed by ERCOT and falls under the jurisdiction of the Texas Public Utility Commission, a contract is not required with each ERCOT member.

The Company and the Cooperative filed an application to transfer the Cooperative’s certified territory to the Company. This was the last step in the conversion process. Several parties intervened in that proceeding and they are seeking to stop the transfer of the CCN. Alternatively, these Opposing Intervenors are requesting a ruling that the Company would be regulated as an investor owned utility by the Public Utility Commission of Texas (“PUCT”) rather than as a cooperative. The Public Utility Regulatory Act currently provides that a successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the members of the electric cooperative, will be considered as a cooperative for regulatory purposes. The Opposing Intervenors argue that the Company does not qualify for such treatment and have attacked the validity of the vote of the Cooperative’s members that approved the conversion process. The Opposing Intervenors have also requested the PUCT to require the Company to “unwind” the conversion or, if it is determined that the conversion cannot be “unwound,” to regulate the Company as an investor owned utility for state regulatory purposes. As another alternative, the Opposing Intervenors seek to have restrictions placed on the Company if the CCN is transferred. As a result, until there is a Final Order by the PUCT on this issue, it is uncertain whether the Company will be considered a cooperative or an investor owned utility for regulatory purposes or, if the Company is determined not to be an investor owned utility for state regulatory purposes, whether any restrictions will be placed upon the Company’s operations.

A hearing was held before Administrative Law Judges in Austin, Texas in June 2002. A Proposal for Decision (“PFD”) was issued by the Administrative Law Judges on September 25, 2002. The PFD recommend that the Company be found to have taken proper steps to qualify for continued treatment as a cooperative under PURA. It further recommended that the CCN be transferred. The PFD also recommended that the Company be required to comply with certain conditions as part of the transfer of the CCN. Those conditions would require the Company to reduce its general and administrative expenses to no more than 30% of its gross margins, prohibition from making future acquisitions that are unrelated to providing reliable electric service to its existing customers, require any acquisitions to first be approved by the PUCT, require maintenance of separate books and records for its electric divisions which are distinct from its existing subsidiary and non-electric operations, and require filing of outage reports under PUCT Substantive Rules 25.5 and 25.81.

The PFD was considered by the PUCT at an open meeting held on November 7, 2002. At the open meeting, the PUCT made no ruling, but requested the Company and Opposing Intervenors file briefs in response to questions outlined by the Commissioners. Briefs were filed and matters were considered by the PUCT at the open meeting held on November 21, 2002. At that meeting, the PUCT made no ruling, but requested an opinion from the Attorney General of the State of Texas as to whether an electric cooperative may convert to a shareholder corporation by transferring all of its assets and liabilities to a shareholder owned corporation that it had created. The Attorney General has not yet rendered an

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opinion. Once the opinion from the Attorney General has been rendered, the matter will again go before the PUCT for consideration.

Senate Bill 1280 (“SB 1280”) is proposed legislation in the Texas Legislature which, if passed, would amend the Public Utility Regulatory Act, to treat a successor to an electric cooperative as an investor owned utility. SB 1280 also provides for establishment of schedules and procedures by the PUCT for those successors which were not previously subject to regulation as an investor owned utility prior to September 1, 2003. Although the bill has passed in committee, it must pass in both the Texas Senate and Texas House of Representatives before it becomes law.

Delays in receiving final approval may impact the Company’s timing and ability to refinance its debt. The Company cannot predict all potential ramifications that may occur as a result of the passage of SB 1280 or regulation by the PUCT. While the Company believes it will ultimately prevail, it is impossible to predict the outcome of these proceedings or any restrictions that the PUCT may place upon the Company.

In March 2002, the Company received a demand letter from an attorney claiming to represent members or shareholders of the Cooperative. Such letter purports to be a derivative action demand under Article 5.14 section C of the Texas Business Corporation Act. The letter generally asserts wrongdoing by the Board and management because the vote at the October 20, 1998, membership meeting at which the conversion plan was adopted was not a valid vote. Management is currently evaluating the demand. The Company believes the claims outlined in the letter have no merit.

The Company is involved in various other litigation matters, none of which is expected to have a material impact on the financial condition, operating results or liquidity of the Company.

27. INCOME TAXES

The Cooperative and NewCorp are tax-exempt organizations under Internal Revenue Code Section 501(c)(12). Energy, Capstar, New West and CRCFC are taxable organizations for Internal Revenue Service purposes and file separate federal income tax returns. For the nine months ended December 31, 2001, and the year ended March 31, 2001, Energy, Cap Star and New West incurred no tax liability.

The Company accounts for income taxes in accordance with SFAS No. 109 “Accounting for Income Taxes,” which requires the recognition of a liability or an asset, net of a valuation allowance, for the deferred tax consequence of all temporary differences between the tax basis and the reported amounts of assets and liabilities, and for the future benefit of operating loss carryforwards.

The following is a reconciliation of income tax expense as shown in the consolidated statement of operations for the year ended December 31, 2002:

Income tax expense at statutory rate (34%)	$	3,125
Income from nontaxable entities	(1,626		)
State tax expense	132
Increase in operating loss and other carryovers	(2,680		)
Change in effective tax rate of operating loss carryovers	(295		)
Change in valuation allowance	1,599
Other	159
Tax expense	$	414

The following is an analysis of the consolidated income tax expense for the year ended December 31, 2002 (in thousands):

Current	$	414
Deferred	—
Tax expense	$	414

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The tax effects of significant temporary differences and carryforwards at December 31, 2002, are as follows (in thousands):

Net deferred tax assets (liabilities):

Accrued expenses	$	333
Allowance for doubtful accounts	18
Net operating loss carryforwards	7,057
Total deferred tax assets		7,408

Deferred revenue	(521		)
Property and equipment	(19		)
Total deferred tax liabilities		(540	)

Valuation allowance	(6,868		)
Net deferred tax asset (liability)	$	—

In addition to the net deferred tax assets (liabilities) detailed above, there exists a $7.7 million capital loss carryover on a consolidated basis available for future use which expires in 2004.

As of December 31, 2002, the Company has net operating tax loss carryforwards of approximately $19.1 million, of which approximately $18.5 million are related to subsidiaries not included in the consolidated income tax return, and $.6 million which are included in the consolidated income tax return. The net operating loss carryforwards are scheduled to expire in 2008 through 2021. The Company has benefited approximately $1.2 million of net operating loss carryforward attributable to one of its subsidiaries because it believes it has tax planning strategies available to realize its tax loss carryforwards. A valuation allowance reduces deferred taxes based on the criteria set forth in SFAS 109.

The components of the consolidated net deferred tax assets and liabilities as of December 31, 2001, are as follows (in thousands):

Deferred tax assets:
Net operating losses	$	5,269
Capital loss carryover	2,718
Net deferred tax assets	7,987
Deferred tax liabilities:
Patronage dividends	(1,670		)
Other	—
Net deferred tax liabilities	(1,670		)

Valuation allowance	(6,317		)

Net deferred tax asset (liability)	$	—

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28. SEGMENT INFORMATION

The Company has adopted SFAS No. 131, “Disclosures about Segments of a Business Enterprise and Related Information.” Substantially all of the Cooperative’s operations are conducted in Texas and involve the following business segments:

Utility—electric sales and various electric services;

Other—oil and gas, real estate and other investments; and

Corporate—general corporate activities including cash and temporary cash investments, various notes receivable, miscellaneous investments and interest expense.

Business segment information as of and for the year ended December 31, 2002, nine months ended December 31, 2001, and the year ended March 31, 2001, is as follows (in thousands):

	UTILITY		OTHER			CORPORATE			TOTAL
Operating revenues
December 31, 2002	$	74,202	$	435		$	—		$	74,637
December 31, 2001	52,769		353			—			53,122
March 31, 2001	71,715		750			—			72,465
Net income (loss)
December 31, 2002	15,217		280			(6,721		)	8,776
December 31, 2001	11,478		32			(7,080		)	4,430
March 31, 2001	8,320		(3,873		)	(8,628		)	(4,181		)
Identifiable assets
December 31, 2002	184,778		4,083			22,433			211,294
December 31, 2001	189,456		4,026			20,977			214,459
March 31, 2001	192,054		4,397			24,744			221,195
Capital expenditures
December 31, 2002	1,517		—			—			1,517
December 31, 2001	4,257		76			—			4,333
March 31, 2001	9,714		360			—			10,074
Depreciation and amortization
December 31, 2002	9,198		55			—			9,253
December 31, 2001	8,284		44			—			8,328
March 31, 2001	10,576		287			—			10,863
Interest expense, net
December 31, 2002	—		—			7,103			7,103
December 31, 2001	—		—			8,004			8,004
March 31, 2001	—		—			11,832			11,832

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29. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes results for each of the four quarters in the years ended December 31, 2002 and 2001 (in thousands except per share data):

	QUARTER ENDED
	MARCH 31,		JUNE 30,		SEPTEMBER 30,		DECEMBER 31,

Period ended December 2002 (Successor)
Total revenues	$	18,119	$	18,300	$	20,774	$	17,444
Operating income	4,226		2,509		5,584		2,354
Net income before income taxes	2,782		925		4,468		1,015
Income tax expense	—		—		—		414
Basic and diluted earnings per share	2.14		.71		3.43		.46

	QUARTER ENDED
	MARCH 31,			JUNE 30,			SEPTEMBER 30,		DECEMBER 31,
Period ended December 2001 (Predecessor)
Total revenues	$	20,365		$	18,150		$	21,578	$	13,394
Operating income	2,322			2,343			5,909		1,728
Net income (loss)	(265		)	(199		)	4,743		(114		)
Pro forma net income (loss) per common share	(.20		)	(.15		)	3.64		(.09		)

The Lamar combination costs of $1,357,000 were expensed during the quarter ended December 31, 2002.

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