CAP ROCK ENERGY CORP - 10-K Annual Report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K

x 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, 2003

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		432-683-5422

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(g) of the Act: NONE

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

Yes

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. ý

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 30, 2003, WAS APPROXIMATELY $22,890,307 BASED ON THE CLOSING PRICE OF $17.59 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 22, 2004, WAS 1,567,725.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive Proxy Statement for the 2004 annual meeting of its shareholders, which will be filed with the Commission not later than April 29, 2004, are incorporated by reference into Part III of this report.

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’s objective has always been to provide quality customer service. The Company’s primary focus is on the distribution of electricity to its customers, from the use of its power lines and associated equipment. All costs of purchased power, including the cost of fuel used to generate the power, are passed through to the retail customer. The Company has not and does not plan to engage in the generation of electricity. The Company provides electric distribution service to approximately 35,000 meters in 28 counties covering approximately 13,000 square miles in Texas. This includes 23,000 meters in 17 counties within two operating divisions in the Midland-Stanton area of west Texas (the “west Texas divisions”), 6,100 meters in the central Texas area around Brady, 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 1,500 meters in Farmersville, Texas. No one customer accounted for more than 10% of the Company’s electric revenues during any of the periods presented.

The Company was formed in December 1998 in accordance with a conversion plan adopted by the members of the Company’s predecessor, Cap Rock Electric Cooperative, Inc. (the “Cooperative” or the “Predecessor”), which was incorporated as an electric cooperative in the State of Texas in 1939. The conversion plan 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 discounted cash, credit on their electric bill over a 24 month period, or common stock in the Company, at the member’s option. 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. The Certificate of Convenience and Necessity (“CCN”), which allows a company to provide electric utility services within a certified territory in Texas, was transferred effective September 1, 2003. On February 8, 2002, the Company issued common 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. Payments were completed by late 2001 for members who chose the discounted cash payment option. The former members who chose credits on their electric bill have received those credits, with such credits being fully applied by the end of 2003.

Electric Market

In the United States, revenues from sales of electricity to ultimate consumers total over $250 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. While the Company is not currently participating in competition as provided for in the 2000 legislation, it has operated in dually certified areas since its existence. Now that the Company is regulated by the Public Utility Commission of Texas, it will be required to comply with the provisions of the 2000 legislation in the future. See State and Federal Regulation – State Regulation. The Company plans to continue to concentrate on customer service as a distribution, or wires, company rather than being heavily involved in the higher risk business of power supply. Therefore, the Company will not face the same risks, such as loss of customers due to customer choice, that other retail electric providers face. Rather the Company will continue to serve its customers by delivering electric energy to its customers over its lines regardless of where the energy is purchased.

Many electric utility companies may not be able to meet the demands of a newly competitive marketplace due to their size or lack of expertise. The Company has experience serving customers in more sparsely

populated areas, a majority of which are dually certified with another utility. This experience in a competitive marketplace gives the Company an advantage over other similar sized electric utilities. The Company expects that as competition becomes more intense and operations become more complicated, more and more small to medium sized electric utility businesses will want to divest their electric systems for some of the same reasons that the Company converted 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. See also “Business-Business Strategy.”

Business Strategy

The Company’s primary focus has been quality customer service. Management plans to continue that focus as it implements a long term strategy of acquiring customers in various locations and regions across the United States for its electric distribution business. The Company believes that mergers and acquisitions will help it increase its customer base and thus put it in a position to compete effectively in a deregulated marketplace.

The Company’s objective is to become a national electric distribution company with community-focused local operating divisions. The strategy is to grow by acquiring small to medium sized electric distribution businesses in rural areas that have the potential for growth.

At the present time, the Company’s largest service area is in west Texas, where it primarily serves residential customers, 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 its service areas, circumstances that are 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 urban 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 these service 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 these areas would provide the Company with a significant opportunity to grow and diversify.

The Company’s business strategy is a continuation of the former Cooperative’s successful history of growing through acquisitions. 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 also Note 23 to the consolidated financial statements, “Commitments and Contingencies,” related to the unsuccessful acquisition of the Lamar Cooperative.

Seasonal Nature of Business

The Company’s operating revenues come from electric or electric related sales. Annual sales for 2003 to the Company’s commercial/industrial, residential and irrigation customers accounted for approximately 52%, 41%, and 7%, respectively, of total electric sales. This trend has remained fairly constant.

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. Oil and gas prices have risen over the past few years. Oilfield activity, and thus electric demand and consumption, may increase because of new drilling programs and the resulting new production.

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 period July 1 to 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. Although irrigation sales are only 7% of all electric sales, approximately 70% of those irrigation sales occur during the period April 1 to September 30.

Non-Electric Business Investments

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 the consolidated financial statements.

In the past, the Company invested in the oil and gas exploration and production business. In December 2000, the Company merged its mineral and royalty company with another company with similar goals. The merged company, Map Resources, Inc. (“MAP”), owns oil and gas minerals and royalties and some non-operated working interests. The Company accounted for its 42% interest in MAP using the equity method of accounting. Effective October 8, 2003, the Company reached an agreement with MAP to sell its entire interest in exchange for a note receivable of $1,250,000 due in October 2004.

The Company has a 10% interest in United Fuel and Energy Company (“United Fuel”), which is engaged in the petroleum distribution business, with a right to acquire an additional 10% interest. In January 2001, the Company acquired an additional 5% interest in United Fuel from certain selling shareholders of United Fuel, giving the Company a 15% interest in the petroleum distribution company. The Company has a right to acquire up to 25% of the stock of United Fuel. The Company also had a note receivable from United Fuel which was extinguished by United Fuel taking the Company’s position as borrower on a cross-collateralized note payable. The Company is a secondary guarantor on United Fuel’s note of $3,500,000. In March 2004, the Company signed an agreement with a shareholder of United Fuel to sell its shares of stock. Consummation of the sale is contingent upon certain future events, such as United Fuel's capitalization arrangements. See Notes 8 and 14 to the consolidated financial statements.

The Company’s real estate investments consist primarily of an office building and the associated land. The Company is also an investor in certain limited partnerships which own and operate interests in real properties. The real estate partnerships were sold in February 2004. See “Properties” for additional information.

Employees

As of December 31, 2003, the Company had 112 full-time and two part-time employees, none of which were members of any labor unions.

State and Federal Regulation

State Regulation

As a Texas electric utility, we are subject to the jurisdiction of the Public Utility Commission of Texas (“PUCT”), which has general regulatory authority over our rates, our certificated territory, and the sale of certain facilities. At the time of the Company’s conversion from an electric cooperative to an investor owned electric utility, the Texas Public Utility Regulatory Act (“PURA”) provided that a successor to an electric cooperative, such as the Company, would be treated as a cooperative for regulatory purposes. This would have allowed the Board of Directors of the Company to continue to set the rates that it charges its customers and to decide when and if to enter into competition. However, during the 2003 Texas legislative session, Senate Bill 1280 (“SB 1280”) was adopted which amended the PURA so that the Company would be treated as an investor owned utility subject to regulation by the PUCT. The Company’s rates are now subject to regulation and approval by the PUCT, rather than the Company’s Board of Directors, and the PUCT will determine how and when the Company will enter into competition. In accordance with this change in the PURA, the Company filed its electric service tariffs with the PUCT in September 2003. The PUCT is currently reviewing those tariffs. In addition, the PUCT initiated an inquiry to determine the reasonableness of the Company’s electric rates and required the Company to submit a standard rate filing package. The Company submitted that rate filing package in late February 2004.

Federal Regulation

A subsidiary of the Company, NewCorp Resources Electric Cooperative, Inc. (“NewCorp”) owns the transmission system that serves the west Texas divisions and is subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). FERC has authority over wholesale sales of electricity, the transmission of electric power, maintenance of accounting records in accordance with the uniform system of accounts and the issuance of certain securities. The Company is exempt from all provisions of the Public Utility Holding Company Act of 1935, except Section 9(a)(2), which relates to the acquisition of the securities of other utilities. See also Note 23, “Commitments and Contingencies,” to the consolidated financial statements.

The 1992 Energy Policy Act began deregulating the electricity market for generation. The Energy Policy Act permitted FERC to order electric utilities to allow third parties to use their transmission systems to sell electric power to wholesale customers. In 2003, NewCorp applied for and received permission from FERC to charge open access transmission system rates for wholesale transactions. FERC also requires the Company to provide transmission services to others under terms comparable to those we provide ourselves. In December 1999, FERC issued an order (FERC Order No. 2000) encouraging formation of regional transmission organizations (RTOs). RTOs are designed to control the wholesale transmission services of the utilities in their regions, thereby facilitating open, and more competitive, markets in bulk power. In February of 2004, FERC issued an order granting RTO status to the Southwest Power Pool (“SPP”).

The Company and all other electric utilities with interstate transmission facilities operate under FERC regulated open access tariffs that offer all wholesale buyers and sellers of electricity the same transmission services, at the same rates, that the utilities provide themselves. Our 305 mile transmission system that serves the west Texas divisions is currently in the SPP. Our 18 mile intrastate transmission system that serves the operating division in central Texas is in the Electric Reliability Council of Texas (“ERCOT”). Management believes that FERC Order No. 2000 and continued participation in the SPP and ERCOT will not have a material effect on its operations.

Competition and Restructuring in the Utility Industry

The Company faces 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 some cases, the Company’s prices are higher than those of Oncor and other retail electric providers, 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. In the future, the Company’s customers may be able to purchase electricity from other providers, however, the Company will continue to provide distribution services and receive a wires charge. See “Business-State and 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 divisions, 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 central Texas 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 approved, the unbundling of transmission rates relating to its west Texas transmission system.

Power Requirements

The Company purchases power for resale to its retail customers from wholesale suppliers and distributes that power to its customers over approximately 320 miles of transmission lines and approximately11,000 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. The Company, through NewCorp, owns and operates a 305 mile transmission system that supplies wholesale power to the Company’s west Texas divisions. NewCorp is a part of the Southwest Power Pool. SPP coordinates transmission services among its members. In 2003, the Company purchased all electric power pursuant to wholesale electric power contracts with Southwestern Public Service Company (“SPS”), Lower Colorado River Authority (“LCRA”) and Garland Power and Light (“Garland”), which accounted for approximately 74%, 14% and 12%, 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 and LCRA expire in 2013 and 2016, respectively. The contract with Garland had an expiration date of 2004, but has been extended until 2005. 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, there is adequate supply of power and generation within the region should the Company need alternative power supplies. All costs associated with purchased power are passed through to the retail customer. For additional discussion of our business segment see “Non-Electric Business Investments” and Note 23 to the consolidated financial statements.

Environmental Matters

The Company is subject to federal and state regulations with respect to certain environmental matters. The Company is unaware of any present or potential environmental problems and believes it is in compliance with all environmental regulations. The laws applicable to environmental concerns can change rapidly and are difficult to predict. Substantial expenditures may be required to comply with these ever changing regulations. The Company analyzes the potential costs arising from environmental matters on an ongoing basis.

Construction and Capital Requirements

The Company has no major construction projects planned at the present time. Utility construction expenditures for 2004 will consist primarily of costs to maintain the Company’s transmission and distribution systems. Total gross property additions, including construction work in progress, for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, were $5,209,000, $1,517,000, and $4,257,000, respectively. Management’s planned capital expenditures for the next 12 months are $4,600,000.

Company Website

The Company’s website address is www.caprockenergy.com. The Company’s reports on Form 10-K and quarterly reports on Form 10-Q are available free of charge at this website. These reports are made available on the website as soon as practicable after filing with, or furnishing to, the Securities and Exchange Commission.

ITEM 2. PROPERTIES

Transmission systems normally carry high voltage electricity over long distances, whereas distribution lines carry lower voltage power from a substation to customers. The transmission system that serves the west Texas divisions 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, which allows for monitoring of voltage and current, and assists in operations. All present substation transformers have in-service dates between 1975 and 1995. The 16 substations supply sixty-six distribution line circuits, which serve over 9,800 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 45,000 square foot office building located in Midland, Texas, that is used as its general corporate headquarters. The Company occupies approximately 35% 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, including right-of-ways, easements and land where substations, transmission and distribution lines are located, and division office locations in Stanton, Colorado City, Brady and Celeste, Texas.

ITEM 3. LEGAL PROCEEDINGS

There is no other litigation pending or threatened against the Company, other than certain legal proceedings arising in the ordinary course of business, none of which are expected to have a material impact on the Company’s financial condition, operating results or liquidity.

See Note 23, “Commitments and Contingencies,” to the consolidated financial statements.

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

There were no matters submitted to a vote of security holders during the fourth quarter of 2003.

Executive Officers of the Registrant

The executive officers of the Company are as follows:

NAME	AGE	POSITION
David W. Pruitt	57	Co-Chairman of the Board, President and Chief Executive Officer

Ulen A. North. Jr.	58	Executive Vice President

Lee D. Atkins	60	Senior Vice President, Chief Financial Officer and Treasurer

Sammy C. Prough	53	Vice President and Chief Operating Officer

Ronald W. Lyon	48	Vice President, General Counsel and Secretary

Celia A. Zinn	55	Vice President, Controller and Assistant Secretary/Treasurer

David W. Pruitt has served as President and Chief Executive Officer of the Company since its inception and as Co-Chairman of the Board since February 2001. He served in those same positions for the Cooperative from 1987 until its dissolution in 2004.

Ulen A. North, Jr. has served as Executive Vice President of the Company since its inception. He served in that same position for the Cooperative from December 1996 until its dissolution in 2004.

Lee D. Atkins has served as Senior Vice President and Chief Financial Officer of the Company since September 2001, and Treasurer since August 2002. 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. He served in the same position for the Cooperative from June 1999 until its dissolution in 2004.

Ronald W. Lyon has served as Vice President and General Counsel of the Company since October 2001, and Secretary since August 2002. Prior to that he was engaged in the private practice of law and served as full-time general counsel to the Cooperative from 1993 until its dissolution in 2004.

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

Market Information and Holders of Common Stock

The Company’s common stock was initially issued on February 8, 2002, and began trading on the American Stock Exchange on March 14, 2002, under the symbol “RKE.” The following table sets forth the range of high and low sales prices per share of common stock for the periods shown, as reported in the consolidated reporting system of 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 exchange until March 14, 2002, there was no previous market for the shares.

	2003				2002
Quarter ended	High		Low		High		Low

December 31	$	32.99	$	27.85	$	11.65	$	10.10
September 30	35.50		17.51		12.35		11.25
June 30	21.50		10.35		12.60		7.20
March 31	11.85		10.25		—		—

As of March 22, 2004, there were 12,312 holders of record of the Company’s common stock.

Dividend Policy

At the present time, the Company has not issued 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. Any dividends declared would be subject to the prior rights of holders of any outstanding cumulative preferred stock. Certain Company loan documents restrict the Company’s payment of dividends.

ITEM 6. SELECTED FINANCIAL DATA

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth selected consolidated financial statement information for the years ended December 31, 2003 and 2002, nine months ended December 31, 2001 and 2000, and the years ended March 31, 2001 and 2000. The following selected consolidated financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data.”

	YEARS ENDED DECEMBER 31,						NINE MONTHS ENDED DECEMBER 31,						YEARS ENDED MARCH 31,
	2003			2002			2001 (2)			2000			2001			2000(1)
										(UNAUDITED)
	— — — — — — — — — — — — — — — (Thousands of dollars)— — — — — — — — — — — — — — —
CONSOLIDATED STATEMENTS OF OPERATIONS DATA:

Operating revenues	$	82,852		$	74,637		$	53,122		$	52,100		$	72,465		$	56,391
Operating expenses (3)	(62,983		)	(59,964		)	(43,142		)	(50,101		)	(68,144		)	(51,773		)
Operating income	19,869			14,673			9,980			1,999			4,321			4,618
Other income (expense)	(6,573		)	(5,483		)	(5,550		)	(5,915		)	(8,502		)	(10,357		)
Income (loss) before income taxes	13,296			9,190			4,430			(3,916		)	(4,181		)	(5,739		)
Income tax expense (4)	(2,098		)	(414		)	—			—			—			—
Net income (loss)	$	11,198		$	8,776		$	4,430		$	(3,916	)	$	(4,181	)	$	(5,739	)

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

Net income (loss)							$	3.40					$	(3.21	)
Pro forma shares outstanding							1,302,355						1,302,355

NET INCOME PER COMMON SHARE:
Basic	$	7.69		$	6.74
Diluted	$	7.41		$	6.74

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	1,455,443			1,302,355
Diluted	1,510,741			1,302,355

	DECEMBER 31,												YEARS ENDED MARCH 31,
	2003			2002			2001			2000			2001			2000
										(UNAUDITED)
	— — — — — — — — — — — — — — — (Thousands of dollars)— — — — — — — — — — — — — — —
CONSOLIDATED BALANCE SHEET DATA:

Utility plant, net	$	152,162		$	156,517		$	164,547		$	170,111		$	168,920		$	169,537
Total assets	202,989			211,294			214,459			218,382			221,195			200,881
Long-term debt, net	143,372			148,052			181,732			184,688			188,627			140,333
Equity and margins							7,672			6,012			5,675			12,659
Stockholders’ equity	26,973			14,738

(1)	The Cooperative acquired McCulloch Electric Cooperative, Inc. effective September 1, 1999. McCulloch’s operations subsequent to the acquisition are included in the consolidated statements of operations.
(2)	The Company changed its year-end from March 31 to December 31, effective December 31, 2001.
(3)	Includes $1,357,000 of impaired costs related to the Lamar Combination for the year ended December 31, 2002. See Note 5 to the consolidated financial statements.
(4)	Upon conversion to a shareholder owned corporation, the activities and transactions of the Company became taxable.

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 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, but are not limited to:

• Weather conditions;

• Change in rate structure and ability to earn a fair return on our rate base and recover the costs of operations;

• Federal and state regulatory actions, and associated legal and administrative proceedings, especially as they relate to the oversight authority of the Public Utility Commission of Texas;

• Increased competition in the electric utility industry;

• Demands for electric power and the associated costs, including changes in the costs of power plant fuels such as natural gas and coal;

• Changes in the Company’s cash position and availability of capital resources;

• The impact of changes in interest rates;

• Changes in federal and state tax laws;

• Unexpected changes in operating expenses and capital expenditures.

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, 2003, 2002 and 2001, and the nine months ended December 31, 2001, should be read in conjunction with the Company’s audited consolidated financial statements and

related notes to financial statements included elsewhere in this document. Unless otherwise indicated, all references to the Company will include any and all activities of its Predecessor.

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 covering approximately 13,000 square miles in Texas. This includes 23,000 meters within two operating divisions in the Midland-Stanton area of west Texas, 6,100 meters in the central Texas area around Brady, 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 1,500 meters in Farmersville, Texas.

The Company purchases power from wholesale suppliers and distributes that power to its retail 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 2003, the Company purchased all electric power pursuant to wholesale electric power contracts with three suppliers. 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 fuel used to generate that electricity, which is primarily natural gas and coal. However, all costs associated with purchased power are passed through to the retail customer.

Effective September 1, 2003, the Company became subject to the oversight authority of the PUCT, and the rates and fees charged to customers by the Company are now subject to PUCT approval. In accordance with this change, the Company immediately filed its tariff for electric service with the PUCT. The Company was required to submit a standard rate filing package to the PUCT in late February 2004, in connection with the PUCT’s review of the reasonableness of the Company’s rates, and its request for a rate increase for some customer classes. Because some parties have intervened in the process, Management believes the proceedings will take a longer period of time, require dedication of more resources and ultimately cost the customer more. The Company is focused on being compliant with any rate case proceeding, but is concerned about the short and long term effects on its resources if the Intervenors requests are voluminous and burdensome.

In its sustained efforts to divest itself of nonutility assets, the Company reached an agreement with MAP to sell its shares of stock in exchange for a note receivable of $1,250,000 due in October 2004. Although the investment appreciated over the period that the Company held it, the sales price was less than recorded book value, and the Company was required to record a loss on the sale of $1,056,000. Upon receipt of the proceeds from the note receivable, the Company will have recouped its original cash investment.

At September 30, 2003, the Company had a note payable to a bank for $11,675,000 which was cross-collateralized by notes receivable from United Fuel and Energy Corporation (“United Fuel”) in the same amount. In October 2003, United Fuel consummated financing with a lender that provided for funds to partially pay down the Company’s note payable to a bank, with United Fuel taking the position as borrower on the Company’s note payable to a bank, thus extinguishing United Fuel’s note receivable to the Company. The Company is no longer a borrower and its involvement has been reduced to being a secondary guarantor for United Fuel’s note of $3,500,000. FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” requires the Company to record a guarantee obligation that is measured at fair value. The Company’s calculation of fair value included factors such as being a secondary guarantor and the collateralization of United Fuel’s assets. The Company has calculated its exposure and recorded a guarantee obligation of $35,000 in October 2003. Upon United Fuel’s repayment of the note and the bank’s release of the guaranty, scheduled for October 2004, the Company will be able to eliminate the recorded obligation. In March 2004, the Company signed an agreement with a shareholder of United Fuel to sell its shares of stock at a sales price of $1,300,000. Consummation of the sale is contingent upon certain future events, such as United Fuel’s capitalization arrangements. It is unknown when those events will transpire.

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 described 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 and estimates are subject to an inherent degree of uncertainty. These judgments and estimates 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. Management believes 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, it is believed 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 the most critical financial estimates with the Board of Directors’ Audit Committee.

The Company’s most critical accounting policy involves rate regulation. The Company is subject to the provisions of Statement of Financial Accounting Standards (“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 deferred on the balance sheet until matching revenues are recognized, subject to regulatory approval. It is the Company’s policy to assess the recoverability of costs recognized as regulatory assets in accordance with SFAS No. 71, based on each regulatory action and the criteria set forth in SFAS No. 71. Any disallowance of these deferred costs would be charged against income immediately upon that disallowance.

Power Cost Recovery Factor. The power cost recovery factor is the difference between the cost of power purchased and the cost of power recovered from the customers, divided by the number of kilowatt hours billed during the period. Power purchased includes transmission costs and wheeling charges. This factor is estimated each month to recover actual power costs and is added as a surcharge to the base rate. The factor is based on estimates of power cost increases/decreases due to changes in fuel cost, usage and other cost fluctuations. The estimate is adjusted in the subsequent month as compared to actual activity. The Company currently defers the difference between actual purchased cost and billed cost as a regulatory asset or liability. The regulatory asset or liability, as well as the deferral, are adjusted in the next period by either receipt from, or refund to, the customer the net deferred amount.

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. As of December 31, 2003, no derivative portfolio was held.

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” when the customer is billed and not on an accrual basis, which recognized revenue as the power is distributed to the customer. By utilizing the “as billed” method, unbilled revenue was not recognized.

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

Stock Based Compensation. Effective January 1, 2003, the Company adopted the fair value method of accounting for its employee stock incentive plan in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation, Transition and Disclosure.” Under the historical or retroactive transition method allowed by SFAS No. 148, the compensation expense for the year ended December 31, 2002, would not have been different had the fair value method been originally applied.

Tax Liabilities and Valuation of Deferred Tax Assets. The Company is required to assess the ultimate realization of deferred tax assets generated from net operating losses, and capital losses incurred on the sale of assets. This assessment takes into consideration tax planning strategies within our control, including assumptions regarding the availability and character of future taxable income. At December 31, 2003, we have recorded $8,074,000 of valuation allowances against net deferred tax assets for which the ultimate realization of the tax asset is mainly dependent on the availability of future taxable income and capital gains. The ultimate amount of deferred tax assets realized could be materially different from that recorded, as impacted by changes in federal income tax laws and upon the generation of future capital gains to enable us to realize the related tax assets.

At December 31, 2003, we also had approximately $7,057,000 of net operating loss carryforwards that expire in 2008 through 2021, and may be used to offset future taxable income. We recorded valuation allowances against the deferred tax assets related to net operating losses. This determination was based on our assessment that it is more likely than not that the Company may not be able to realize these deferred assets during the carryforward period. This assessment considered the forecast reversal of existing temporary differences and taxable income expected to be generated in the carryforward period.

Impairment of Long-lived Assets. Management reviews the carrying value of long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” Unforeseen events and changes in conditions could indicate that these carrying values may not be recoverable and may therefore result in impairment charges. An impairment loss is recognized only if the carrying amount of the long-lived asset is not recoverable and exceeds its fair value. The carrying amount of a long-lived asset is not recoverable if it exceeds its future undiscounted cash flows, and if required, fair value of long-lived asset is written down to its fair value. The determination of future cash flows, and if required, fair value of long-lived asset is by its nature a highly subjective judgment. Fair value is determined by calculating the discounted future cash flows using a discount rate, third party contracted bids or appraisals performed by a qualified party. Significant judgments and assumptions are required in the forecast of future operating results used in the preparation of the long-term estimated cash flows, including long-term forecasts of the amounts and timing of overall market growth. Changes in these estimates could have a material effect on the assessment of our long-lived assets.

Postretirement Healthcare Benefits. The Company provides certain postretirement healthcare benefits to employees and retirees. Determining the costs associated with such benefit is dependent on various actuarial assumptions including demographics (age, sex), mortality rates, discount rates used in determining the projected benefit obligations, and current and projected health care cost trend rates. Independent actuaries perform the required calculations, in accordance with accounting principles generally accepted in the United States. Actual results that differ from the actuarial assumptions are generally accumulated and amortized over future periods.

Results of Operations

	Year Ended December 31,						Nine Months Ended December 31,
	2003		2002		2001		2001
	Successor		Successor		Predecessor		Predecessor
					(Unaudited)
	— — — — — — — — — — — —(Thousands of dollars)— — — — — — — — —
Operating Revenues:
Electric Sales	$	81,402	$	73,335	$	72,417	$	52,326
Other	1,450		1,302		995		796
Total operating revenues	$	82,852	$	74,637	$	73,412	$	53,122

The consumption and demand for electricity within the Company’s service areas is greatly impacted by weather conditions and temperatures. The hot temperatures during the summer months, or the third quarter, require residential customers to use more electricity in cooling their homes. Rural customers who irrigate crops use more electricity in the summer months for the irrigation process, and if the spring season didn’t bring much rain, these customers may irrigate sooner and longer. Portions of the Company’s service areas have been experiencing a severe long-term drought. The National Weather Service Climate Prediction Center shows only minimal relief for the ensuing year.

Electric revenues increased $8,067,000 for 2003 as compared to 2002. This rise is due to multiple factors:

• Adjustments of $3,060,000 for recovery of increased power costs from prior periods were billed to customers;

• A regulatory surcharge of $1,539,000 was billed to customers, which related to intervention costs;

• A change in accounting principle, described in Note 1 to the consolidated financial statements, from the “as billed” method to the accrual method, increased electric revenues by $3,400,000;

The regulatory surcharge, authorized by the Company’s Board of Directors, was intended to recover some of the expense incurred in connection with the Company’s response to Opposing Intervenors actions, and such surcharge has concluded.

The Company had been realizing deferred revenue of $4,364,000 equally over a 24 month period from January 2002 to December 2003. Although this revenue is recognized equally in both the 2003 and 2002 periods, it has been fully billed through the power cost recovery factor, and will not be reflected in future periods. This item related to purchased power expensed in prior years, but was recovered from customers over a 24 month period. This type of item may occur in the future because of the protocol mandated by FERC for administration of the transmission tariff. See also Note 17 to the consolidated financial statements. Electric revenues for 2002 were $918,000 greater than those for 2001 because of the aforementioned recognition of deferred revenue related to recovery of power cost from prior periods, offset by a decrease in 2002 power cost recovery.

At the time of the Company’s conversion from an electric cooperative to an investor owned electric utility, the Texas Public Utility Regulatory Act provided that a successor to an electric cooperative, such as the Company, would be treated as a cooperative for regulatory purposes. This would have allowed the Board of Directors of the Company to continue to set the rates that it charges its customers. In September 2001, the Company and the Cooperative filed an application to transfer the Cooperative’s Certificate of Convenience and Necessity to the Company. The CCN allows the Cooperative and the Company to serve electric customers in certain territories within the State of Texas. Various Intervenors challenged this transfer as well as the Company’s right to treatment as a cooperative for regulatory purposes under the PURA. Following a contested proceeding, the Pubic Utility Commission of Texas approved the transfer of the CCN, effective September 1, 2003.

However, during the 2003 legislative session, Senate Bill 1280 was adopted by the Texas legislature which amended the PURA so that the Company would be treated as an investor owned utility subject to regulation

by the PUCT. The Company’s rates are now subject to regulation and approval by the PUCT, rather than the Company’s Board of Directors. In accordance with this change in the PURA, the Company filed its electric service tariffs with the PUCT on September 2, 2003. The PUCT is currently reviewing those tariffs. In addition, the PUCT initiated an inquiry to determine the reasonableness of the Company’s electric rates and required the Company to submit a standard rate filing package. The Company submitted that rate filing package in late February 2004. The filing contained a request for a rate increase for the Company’s various customer classes, aggregating approximately 14%. The increase is intended to cover increased costs of service related to, among other things, property taxes, computer and IT systems, and costs associated with being a regulated investor owned utility. Several parties have intervened in these proceedings requesting relief from the PUC. The major items being sought by the Intervenors are that the Company’s rates be decreased and that the Company be required to refund all monies it previously collected pursuant to a regulatory surcharge authorized by the Board of Directors during 2003. The Company believes its rates are reasonable and that the requested rate increase is appropriate based upon its cost of service and reasonable return on its invested assets. The PUCT has suspended the proposed rate increase pending a formal hearing and the Company’s current rates will remain in effect. The Company cannot determine what action the PUCT will take with respect to its current rates or its requested rate increase. The PURA requires the PUCT to rule on the rate request within a specified number of days and the Company expects a final ruling in the fourth quarter of 2004.

If the Company’s request for a rate increase is approved by the PUCT, the Company may suffer a decline in consumption by customers. Because the outcome of the rate request or rate order is unknown, the Company is unable to predict the effect of such order.

	Year Ended December 31,						Nine Months Ended December 31,
	2003		2002		2001		2001
	Successor		Successor		Predecessor		Predecessor
					(Unaudited)
	— — — — — — — — — — —(Thousands of dollars)— — — — — — — — — —
Operating Expenses:
Purchased power	$	36,578	$	36,433	$	40,781	$	28,194
Operations and maintenance	10,476		7,327		7,427		5,828
General and administrative	6,471		7,144		4,664		3,326
Depreciation and amortization	7,787		6,134		6,159		4,568
Property taxes	1,345		1,367		1,380		997
Impairment of Lamar combination costs	—		1,357		—		—
Other	326		202		310		229
Total operating expenses	$	62,983	$	59,964	$	60,721	$	43,142

Purchased power expense normally moves in relation to electric demand and consumption. Contract terms with wholesale power suppliers provide for pricing based upon the price of fuel, demand and usage. All costs of power are passed through to the Company’s retail customers. Purchased power only increased $145,000 from 2002 to 2003. The net change is attributable to:

• The change in accounting principle for unbilled revenues in 2003, described in Note 1 to the consolidated financial statements, caused a catch up in the purchased power cost lag of $1,318,000;

• An increase of $1,896,000 in power costs offset by a decrease in net consumption;

• A decrease in wheeling charges of $250,000;

• A conclusion in September 2003 to the rate making treatment of the capital lease payments which were associated with the transmission system. This caused a decrease of $2,773,000.

The cost of natural gas has risen from 2002 to 2003, which has increased the cost of purchased power and is passed directly through to customers. Management expects natural gas prices to remain flat for 2004.

Certain service areas of the Company have experienced a rise in consumption, whereas other service areas reflect a decline in consumption. The weather in the Company’s service area for 2003 as compared to 2002 has been milder: the winter has been less severe, and the summer months didn’t experience as many days over 100 degrees.

Purchased power cost decreased by $4,348,000 in 2002 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. Taking the aforementioned changes in 2001 into account, the nine month period ended December 31, 2001, was comparable in nature to 2002.

As mentioned above, the rate making treatment of the transmission system capital lease payments concluded in September 2003, as a result of final payment on the capital lease. Rate making treatment required the Company to classify the amortization of property and equipment under the capital lease, as well as the associated interest expense, as purchased power. Total amounts included in purchased power which are associated with the capital lease are $4,403,000, $6,490,000, $6,502,000 and $4,882,000 for 2003, 2002, 2001, and the nine months period ended December 31, 2001, respectively. Because the capital lease has been extinguished, this treatment is no longer applicable, and future periods will not reflect this expense. The remaining net book value of the transmission system will be depreciated over its remaining life, and will be reflected in Depreciation and Amortization expense.

Factors affecting operations and maintenance expense are certain weather conditions such as high winds, ice storms and lightning which cause damage to electric lines and interrupt service. Operations and maintenance increased $3,148,000 between 2002 and 2003. The majority of the change is related to an increased need in maintenance for the distribution and transmission systems which resulted in current expense, as opposed to engaging in construction activities that would have resulted in capitalized costs.

In April 2003, each employee was granted a noncash stock award, with vesting over 5 years. Officers, directors and certain retired directors were also granted noncash stock awards in July 2003, with vesting periods ranging from 2 to 5 years. The expense associated with these noncash awards is being amortized to expense over periods of 2 to 5 years. This expense was allocated between Operations and Maintenance expense, and General and Administrative expense, based upon the respective employee’s or officer’s function within the Company. For 2003, the allocation of noncash compensation of $2,021,000 was $340,000 to Operations and Maintenance, and $1,681,000 to General and Administrative. Expected noncash compensation expense by year is as follows: 2004 - $2,317,000, 2005 - $760,000, 2006 - $325,000, 2007 - $316,000 and 2008 - $105,000.

General and administrative expenses decreased by $673,000 between 2002 and 2003. The aforementioned noncash stock awards of $1,681,000 for 2003 were offset by decreases in legal and professional fees, the majority of which were associated with the PUCT proceedings concerning the application to transfer the Cooperative’s certified territory to the Company, as well as decreases in public reporting costs.

The increase of $2,480,000 in general and administrative expense from 2001 to 2002 was primarily due to legal expenses associated with PUCT hearings, discussed previously, and shareholder related costs.

The Company expects general and administrative expenses to increase in the future because compliance with PUCT rules and regulations, as well as the Sarbanes Oxley Act of 2002, will require more personnel.

Depreciation and amortization increased $1,653,000 from the year ended 2002 as compared to 2003 for various reasons:

• Amortization of the fees and costs associated with the original transmission system capital lease were escalated by $544,000, in order that these costs would be fully amortized by the end of the lease term;

• Increased depreciation expense of $359,000 associated with changes in estimated useful lives of certain general plant assets;

• Initial amortization of $333,000 of the legal fees and costs incurred with respect to consummation of the Beal Bank loan;

• Conclusion of the rate making treatment of the amortization of property and equipment associated with the transmission system capital lease caused an increase of $220,000.

In connection with the original ten year capital lease associated with the transmission system, generally accepted accounting principles required the Company to amortize the asset over a period consistent with the lease payments. This period was much shorter than the estimated life of the asset, and the amortization was charged to purchased power. Because the capital lease was extinguished in September 2003, and the rate-making treatment is no longer applicable, the method of depreciation and life of the transmission system assets has changed to a straight-line method with a 20 year remaining life, and the expense is reflected in Depreciation and Amortization expense. The Company estimates the amount of such depreciation on the transmission system to be $864,000 per year.

In its efforts to be able to adapt to a changing regulatory environment, enhance efficiency, automate certain processes, position itself to pursue potential acquisitions and increase its customer base, management recognized the need for a more sophisticated and responsive IT system and associated applications. The Company engaged an objective outside third party to assess the Company’s current and future IT needs, assist in the selection process of software and related applications, implement the chosen products and processes and provide ongoing support. The third party IT company is also assisting the Company in providing IT internal control documentation and procedures in order that the Company may begin the process of compliance with the Sarbanes Oxley Act of 2002.

Certain IT costs associated with the change in the operating environment, the applications and implementation process have been capitalized. These costs, which aggregate $3,881,000 at December 31, 2003, will be amortized over 5 years beginning March 2004. In addition, the ongoing costs for maintenance and IT support is based on the number of meters and will approximate $1,697,000 per year through the term of the contract which is December 2007. All applications are anticipated to be operational by the end of 2004.

Although property tax expense has remained relatively constant for the past few years, the Company anticipates property tax expense for 2004 will materially increase due to current appraisal methodologies used in the ad valorem taxation of investor owned utilities in Texas. Estimates of the Company’s revenue-generating ability are also considered in the appraisal process. The Company has increased its projection for property tax expense for 2004 from $1,345,000 to $3,000,000.

As described more fully in Note 23 to the consolidated financial statements, in 1999 the Company entered into an agreement to combine with Lamar Electric Cooperative (“Lamar”). Lamar terminated the agreement in late 2002. Although the Company is seeking to recover the costs and expenses incurred in connection with the combination, generally accepted accounting principles required the impairment of those capitalized costs, which aggregated $1,357,000.

	Year Ended December 31,									Nine Months Ended December 31,
	2003			2002			2001			2001
	Successor			Successor			Predecessor			Predecessor
							(Unaudited)
	— — — — — — — — — — —(Thousands of dollars)— — — — — — — — — —
Other Income (Expense):
Allocation of income from associated organizations	$	530		$	478		$	1,290		$	1,205
Interest expense, net of capitalized interest	(6,979		)	(7,103		)	(10,818		)	(8,004		)
Interest and other income	788			1,027			1,582			1,161
Loss on sale of MAP stock	(1,056		)	—			—			—
Equity earnings in MAP	144			115			89			88
Total other income (expense)	$	(6,573	)	$	(5,483	)	$	(7,857	)	$	(5,550	)

Although interest expense only decreased $124,000 from 2002 to 2003, the major components changed. Because the Company was able to lock in at some lower interest rates, coupled with a declining principal balance, interest expense on mortgage debt was reduced by $535,000. The cross-collateralized note payable to a bank had a declining balance and was extinguished in September 2003. This was a change of $186,000 between 2002 and 2003. The draw on the initial advance in September 2003 from Beal Bank of 10.75% per annum caused an increase of $478,000.

Interest expense decreased by $3,715,000 in 2002 from 2001 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 rates on the $28,000,000 line of credit were 3.65% and 5.1% for December 2002 and December 2001, respectively.

	Year Ended December 31,					Nine Months Ended December 31,
	2003		2002		2001	2001
	Successor		Successor		Predecessor	Predecessor
					(Unaudited)
	— — — — — — — — — —(Thousands of dollars)— — — — — — — — — — —
Income Tax Expense:
Income tax expense	$	2,098	$	414	—	—

For the year and nine months ended December 31, 2001, the Company incurred no current income tax expense because it was able to utilize net operating loss carryforwards. Income tax expense increased $414,000 in 2002 and $1,684,000 in 2003. As of December 31, 2003, the Company has net operating loss carryforwards of approximately $19.1 million, which are scheduled to expire in 2008 through 2021. The Company has benefited approximately $5 million of net operating loss carryforwards because it has tax planning strategies available to realize the benefit of its tax loss carryforwards.

The IRS has notified the Company that it intends to examine the federal income tax return of the Cooperative for the year 2001. Because the Cooperative is a nontaxable entity, and the Company feels it filed a proper return, management believes that the outcome of the audit will not have a material effect on the Company’s financial position, results of operations or liquidity.

Contractual Obligations and Other Commitments

The following table summarizes the Company’s obligations and commitments to make future payments under certain contractual obligations:

	2004		2005		2006		2007		2008		Thereafter		Total
	— — — — — — — — — — — — — — — — —(Thousands of dollars)— — — — — — — — — — — —

Debt obligations	$	18,700	$	8,330	$	4,586	$	4,721	$	28,430	$	97,121	$	147,719
Capital lease obligations	123		110		57		18		—		—		308
Operating lease obligations	314		97		79		42		27		25		584
Purchase obligations (1)	2,314		1,837		1,837		1,837		140		811		8,776
Other long term liabilities (2)	1,188		1,253		641		659		622		3,128		7,491

Total

(1) All of the Company’s power contracts are firm, full requirements contracts. These types of contracts require the Company to purchase all of its power needs from the seller, but do not mandate a minimum purchase amount. Therefore, amounts included for each year are basic required transmission charges. Also included are commitments for IT services.

(2) Includes actuarially calculated amounts for post retirement healthcare costs of $605,000 $684,000 $709,000 $747,000 and $743,000 for the years 2004, 2005, 2006, 2007, and 2008, respectively, as well as $3,103,000 for 2009 through 2013. Also the Company has a contract with the City of Farmersville, Texas, to provide power and assume related billing and collections functions. The Company is obligated to

the City to make payments on a revenue sharing type basis. The 2004, and estimated 2005, annual payments are $626,000.

Liquidity and Capital Resources

As of December 31, 2003, the Company had:

• Cash and cash equivalents of $12,170,000;

• Current restricted cash investment of $14,169,000;

• Working capital of $9,080,000; and

• Long-term indebtedness of $143,372,000, net of current portion.

The Company requires capital to fund utility plant additions, working capital and other utility expenditures which are recovered in subsequent and future periods through rates. Capital necessary to meet these cash requirements is now derived primarily from internally generated funds.

Through 2001, one of the Company’s primary sources of capital and liquidity had been 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.

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 CFC fixed rate notes are subject to interest rate repricing at the end of various periods, at the Company’s option.

Interest rate		Repricing January	Amount
Fixed	3.35%	2004	$	10,400,000
Fixed	4.20%	2005	69,109,000
Fixed	4.70%	2006	34,128,000
Fixed	4.50%	2007	6,080,000
Fixed	4.30%	—	28,000,000
Fixed	7.00%	—	2,000

Total long term debt			$	147,719,000

NewCorp submitted an application to the Federal Energy Regulatory Commission in July 2003, seeking authorization to borrow $31,500,000 from Beal Bank S.S.B. (“Beal Bank”). FERC approval was received in August 2003. The arrangement with Beal Bank was segregated into two advances. The initial advance provided proceeds of $14,076,000 for payment of the balloon payment on the transmission system capital lease, plus interest of $93,000 for a total of $14,169,000. The additional advance of $17,331,000 provides for $5,500,000 for working capital and cash reserves for operations and maintenance of the transmission system, purchase of transmission assets from Cap Rock Energy Corporation, repayment of a loan to another subsidiary, as well as payment of all costs and expenses associated with the new loan arrangement. The new financing would also allow NewCorp to make such system upgrades, improvements and expansions, as may be necessary.

The initial advance of $14,169,000 was completed in September 2003. Simultaneously, the original lien on the transmission system was released and the sinking fund of $8,207,000 was transferred to a restricted securities account. NewCorp added $5,962,000 to the restricted securities account to bring the total restricted cash

investment to $14,169,000, the amount of the initial advance proceeds. This restricted cash investment is the only asset collateralized by Beal Bank in connection with the initial advance. Upon funding of the additional advance, the restricted cash investment would be released, and the transmission system, receivables and other assets related to the transmission system would be collateral for the full loan.

Interest on the Beal Bank loan is the greater of 10.75% per annum, or 7% plus the one-month LIBOR rate, payable monthly. The initial advance amount of $14,169,000 is due September 9, 2004, unless the additional advance is funded on or before that date, in which case, the entire principal amount would be payable monthly amortized over 15 years. Pursuant to the terms of the financing arrangement, prepayment of the initial advance is not allowed before its scheduled maturity date; prepayment of the additional advance would not be allowed for the first 24 months of the loan period, with a 1% fee if prepayment was made during months 25 through 48. The financing arrangement also provided for a commitment fee of 2% of the total loan amount with $457,000 payable for the initial advance, and the remaining $173,000 payable for the additional advance. Additional customary fees payable to Beal Bank were for reimbursement of expenses, attorney fees, appraisals and consulting. Total fees and costs incurred in connection with the Beal Bank advance through December 31, 2003, aggregated $999,000. Maintenance of certain financial covenants would be required upon funding of the additional advance, and the Company and NewCorp are already in compliance with such future requirements. The Company would be required to maintain consolidated net worth of $5,000,000 and NewCorp would be required to maintain a ratio of net income plus interest, taxes, depreciation and amortization to debt service of at least 1.2 on a rolling quarter basis.

In the accompanying consolidated balance sheet at December 31, 2003, the initial advance of $14,169,000 is shown in current liabilities because it is not certain that the Company will draw on the additional advance from Beal Bank. The Company has other available options, which it may pursue, such as refinancing the debt with another lender, entering into a sale leaseback arrangement or selling the transmission system. All of the options available to the Company are contingent upon the transfer of NewCorp’s CCN. See Note 23, “Commitments and Contingencies,” to the consolidated financial statements. Whether the Company draws on the additional advance with Beal Bank or another option is chosen, the restricted cash investment will be released at the same time. If the Company draws on the additional advance, the restricted cash investment of $14,169,000 would be released and available for use in operations, as well as new capital of $17,331,000. If the Company pursues one of the other options, the restricted cash investment would be used to satisfy the initial advance of $14,169,000, shown in the table for 2004 under “Contractual Obligations and Other Commitments.”

When the regulatory process has been completed and the PUCT issues a final order concerning retail rates, the Company may consider having a secondary common stock offering. The offering could include the issuance of three to five million shares and would be used to reduce debt. This would bring the debt to equity ratio to 60/40, which management believes is more in line with comparable electric utilities. At that time, the Company would also consider implementing a dividend policy.

One of the options offered to the Cooperative’s members in connection with the Company’s conversion from a cooperative to a shareholder owned corporation, was to receive their patronage capital in the form of credits on their utility bills ratably over a 24 month period. These credits were shown as liabilities on the consolidated balance sheets at December 31, 2002 and 2001. The 24 month period ended November 2003. Therefore, cash generated from customer payments of utility billings should increase by approximately $325,000 per year.

Although the outcome concerning the PUCT’s final order on the Company’s retail rates are unknown, with the current working capital position and the availability of other capital, Management feels the Company has adequate resources to meet its obligations for 2004, including those enumerated in the table under “Contractual Obligations and Other Commitments.”

New Accounting Standards

long-lived assets and the associated asset retirement costs. The implementation of this standard did not have a material impact on the Company’s financial position or results of operations.

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” 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, and was adopted by the Company effective January 1, 2003. The implementation of this standard did not have an impact on the Company’s financial position or results of operations.

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. See Note 14 to the consolidated financial statements concerning the Company’s guarantee of debt of United Fuel.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities — an interpretation of ARB No. 51” (“FIN 46”). An additional interpretation, Interpretation No. 46R, was issued by the FASB in December 2003. FIN 46 and 46R require 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 owns no interests in variable interest entities, and therefore neither of these interpretations has affected the Company’s consolidated financial statements.

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 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. Effective January 1, 2003, the Company changed its method of accounting from the intrinsic method per APB Opinion No. 25, to the fair value method per SFAS No. 148, and the impact of such change is not material.

On April 22, 2003, the FASB announced its decision to require all companies to expense the fair value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. Although the new guidelines and ultimate measurement valuation methodology have not yet been released, it is expected that they will be finalized soon and effective in 2004. When final rules are announced, the Company will assess the impact to its financial statements.

In April 2003, the FASB issued Statement No. 149 (“SFAS No. 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting requirements for derivative instruments, including derivative instruments embedded in other contracts, and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In general, SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. Adoption of this statement did not have a material impact on the Company’s financial position or results of operations.

In May 2003, the FASB issued Statement No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS No. 150”). This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is

effective at the beginning of the first interim period beginning after June 15, 2003. Adoption of SFAS No. 150 did not have a material impact on its financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk represents the risk of changes in the value of a financial instrument 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, with a variable charge for fuel cost, which is generally natural gas. This variable cost is affected by unpredictable factors, including weather and worldwide events, which in turn impact supply and demand. The Company’s exposure to purchased power price risk is substantially mitigated because all actual costs of power are able to be recovered from billings to customers.

Credit Risk

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

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

The Beal Bank loan documents related to the restricted cash investment of $14,169,000 at December 31, 2003, provide that the collateral may only be invested in US government securities, bank certificates of deposit, money market funds or other approved investments with varying terms of one year or less. Whether the Company draws on the additional advance with Beal Bank, or another option is chosen, this restricted cash investment will be released at the same time.

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 the customer has paid timely at least 10 of the previous 12 billings. No customer accounted for 10% or more of the operating revenues of the Company.

The Company had a note payable to a bank which was cross-collateralized by notes receivable from United Fuel and Energy Corporation in the same amount, which at September 30, 2003, were $11,675,000. In October 2003, United Fuel consummated financing with a lender that provided for funds to partially pay down the Company’s note payable to a bank, with United Fuel taking the position as borrower on the Company’s note payable to a bank, thus extinguishing United Fuel’s note receivable to the Company. The Company is no longer a borrower and its involvement has been reduced to being a secondary guarantor for United Fuel’s note of $3,500,000. FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” requires the Company to record a guarantee obligation that is measured at fair value. The Company’s calculation of fair value included factors such as being a secondary guarantor and United Fuel’s assets collateralizing the note. The Company has calculated its exposure and recorded a guarantee obligation of $35,000. Upon United Fuel’s repayment of the note and the bank’s release of the guaranty, scheduled for October 2004, the Company will be able to eliminate the recorded obligation.

The Company sold its investment in MAP effective October 2003, in exchange for a note receivable of $1,250,000 due October 2004. The note receivable is collateralized by the original stock. The Company also sold its investments in real estate partnerships in February 2004, in exchange for a note receivable of $286,000 due 2009. There was no gain or loss on the sale. The note is collateralized by the partnership interests. At December 31, 2003, the Company had guaranteed an aggregate of $5,178,000 of debt of some of these partnerships. The sale of the partnership interests also involved the transfer of those guarantees to the buyer.

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. Mortgage notes of $69,109,000 with current interest rates of 4.2% are due to be repriced in January 2005, mortgage notes of $34,128,000 with current interest rates of 4.70% are due to be repriced in January 2006, $3,632,000 of mortgage notes were repriced in January 2004 with a variable interest rate of 2.9% and $6,767,000 of mortgage notes were repriced in January 2004 with an interest rate of 3.05%, to be repriced again in January 2005. The former line of credit of $28,000,000 has a fixed rate of 4.3%. Although all of the Company’s debt is currently at fixed rates, a 1% change in interest rates would cause a change of $1,619,000 in interest expense. The Company attempts to take advantage of low interest rate environments, as well as repricing interest rates over staggered periods.

Changes in market interest rates affect the interest earnings on the restricted cash investment which, at December 31, 2003, had a balance of $14,169,000. The terms of the Beal Bank loan documents provide that the collateral may only be invested in US government securities, bank certificates of deposit, money market funds or other approved investments, with varying terms of one year or less. The weighted average interest rate for the investments for the four months ended December 31, 2003, the period that the investments were held, was less than one percent.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Consolidated Financial Statements are set forth on pages F-1 through F-39 of this Form 10-K.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9(a).

CONTROLS AND PROCEDURES

As of the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. There have been no changes in the Company’s internal controls over financial reporting identified in connection with the evaluation referred to above that materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial report.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Directors And Executive Officers

The information relating to our directors required by Item 10 is set forth in our definitive proxy statement to be filed with the SEC for our 2004 Annual Meeting of Shareholders to be held on June 15, 2004. Such information is incorporated herein by reference to the material appearing under the captions “Election of Directors” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the proxy statement to be filed by us with the SEC.

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by Item 11 will be set forth in our definitive proxy statement to be filed with the SEC for our 2004 Annual Meeting of Shareholders to be held on June 15, 2004. Such information is incorporated herein by reference to the material appearing under the captions “Compensation of Directors,” “Compensation of Named Executive Officers,” “Performance Graph” and “Compensation Committee Report” in the proxy statement to be filed by us with the SEC.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 12 will be set forth in our definitive proxy statement to be filed with the SEC for our 2004 Annual Meeting of Shareholders to be held on June 15, 2004. Such information is incorporated herein by reference to the material appearing under the caption “Beneficial Ownership of Voting Securities” and “Equity Compensation Plans” in the proxy statement to be filed by us with the SEC.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 13 will be set forth in our definitive proxy statement to be filed with the SEC for our 2004 Annual Meeting of Shareholders to be held on June 15, 2004. Such information is incorporated herein by reference to the material appearing under the caption “Certain Relationships and Related Transactions” in the proxy statement to be filed by us with the SEC.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information called for by Part III, Item 14, is included in our proxy statement relating to our annual meeting of shareholders to be held on June 15, 2004, and is incorporated herein by reference.

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 years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001.

Reports on Form 8-K

The following reports on Form 8-K were filed either during the three months ended December 31, 2003, or between December 31, 2003, and the date of this report;

1. October 14, 2003, Item 5. Other Events. Re: Sale of MAP Stock, extinguishment of note payable to bank and note receivable from United Fuel, and new guaranty on United Fuel debt.

2. November 14, 2003, Item 7 and 12. Re: Disclosure of financial results for the quarter ended September 30, 2003.

3. February 26, 2004, Item 5. Other Events. Re: Filing of rate case with Public Utility Commission of Texas.

Exhibits

Exhibit No.		Item
Exhibit 3.1		Articles of Incorporation of the Company and amendments thereto (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 3.2		Bylaws of the Company (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (1)
Exhibit 3.2a		Amended and Restated Bylaws of Cap Rock Energy Corporation(2)
Exhibit 3.3		Restated and Amended Articles of Incorporation of the Cooperative (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (1)
Exhibit 3.4		Bylaws of the Cooperative (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 3.5		Amended and Restated Bylaws of the Company (originally filed with Amendment No. 4 to Form S-1 dated 6/17/01) (1)
Exhibit 3.6		Amended and Restated Articles of Incorporation of the Company (originally filed with Amendment No. 4 to Form S-1 dated 6/17/01) (1)
Exhibit 3.7		Articles of Amendment to the Amended and Restated Articles of Incorporation of the Company (originally filed with Amendment No. 4 to Form S-1 dated 6/17/01) (1)
Exhibit 3.8		Amended and Restated Bylaws of the Company(1)
Exhibit 5.1		Opinion of Ronald W. Lyon (original filed with Amendment No. 3 to Form S-1 dated 5/11/01)(1)
Exhibit 8.1		Tax Opinion of Looper Reed & McGraw, a Professional Corporation (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.1		Second Amendment to Transaction Documents dated November 9, 1994, between Southwestern Public Service Company, the Cooperative, et. al. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (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 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (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 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (1)
Exhibit 10.4		Loan Agreement dated October, 1995, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Form S-1 date July 31, 2001) (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 (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.6		Loan Agreement dated as of June 22, 2000, between the Cooperative and National Rural Utilities Cooperative Finance Corporation and amendment. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.7		Loan Agreement dated December 13, 1994, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.8		Loan Agreement dated March 30, 1993 between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.9		Loan Agreement dated March 10, 1992, TX 107-A-9025, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (1)
Exhibit 10.10		Loan Agreement dated May 17, 1990, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.11		Loan Agreement dated March 22, 1990 between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.12		Notice of Meeting and Proxy Statement for Special Meeting held October 20, 1998 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (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 (originally filed with Form S-1 date July 31, 2001) (1)

Exhibit 10.14		Loan Agreement dated March 10, 1992, TX 107-A-9026, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.15		Purchase and Sale Agreement dated as of February 11, 2000 between the Company, the Cooperative and Citizens Utilities Company regarding Arizona Electric (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.16		Purchase and Sale Agreement dated as of February 11, 2000 between the Company, the Cooperative and Citizens Utilities Company regarding Vermont Electric. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.17		Power Sale Agreement dated May 1, 1999, between the Cooperative and Electric Clearinghouse, Inc. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.18		Wholesale Power Supply and Services Contract dated April 16, 1997 Between Texas New Mexico Power Company and the Cooperative (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.19		Southwestern Public Service Company Wholesale Full Requirements Service Rate Schedule and related Agreement, as amended, with the Cooperative (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.20		Ordinance of the City of Greenville, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.21		Ordinance of the City of Midland, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.22		Ordinance of the City of Stanton, Texas Granting to the Cooperative a franchise for the transmission and distribution of electricity (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.23		Employment Contract between the Cooperative and Ulen North dated July 21, 1992 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.23a		Employment Contract between Cap Rock Energy Corporation and Ulen A. North, Jr. dated September 12, 2001 (2)
Exhibit 10.24		Employment Contract between the Cooperative and David W. Pruitt dated August 3, 1992 (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.24a		Employment Contract between Cap Rock Energy Corporation and David W. Pruitt dated September 11, 2001 (2)
Exhibit 10.25		Achievement Based Compensation Agreement Corporate Asset Non-CFC Financing Arrangements dated August 28, 1994 (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.26		Achievement Based Compensation Agreement Corporate Asset Non-CFC Financing Arrangements dated October 27, 1992 (originally filed with Form S-1 date July 31, 2001) (1)
Exhibit 10.27		The Cooperatives Supplemental Executive Deferred Compensation Retirement Plan (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.28		Cap Rock Energy Corporation 2001 Stock Incentive Plan (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.29		Cap Rock Energy Corporation 2001 Employee Stock Purchase Plan (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.30		Form of Equity & Membership Redemption Options (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.31		Form of Equity Redemption Options (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(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. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(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. (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.34		Consolidating Loan Agreement dated March 30, 1993 between Cap Rock Electric Cooperative, Inc. and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)

Exhibit 10.35		Integrated Supply Agreement between Cap Rock Electric Cooperative, Inc. and Temple, Inc. (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.36		Employment Contract between the Cooperative and Mickey Sims (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.37		Amendment to Line of Credit Agreement dated June 27, 1997 between National Rural Utilities Cooperative Finance Corporation and the Cooperative (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.38		Loan Agreement dated March 10, 1992, TX 107-A-9027, between the Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.39		Achievement Based Compensation Contract, Merger or Acquisition with Other Electric Utilities dated August 22, 2000 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.40		Loan Agreement dated March 10, 1992, TX 107-A-9024, between Cooperative and National Rural Utilities Cooperative Finance Corporation (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 10.41		Wholesale Power Agreement dated June 25, 1977, between Lower Colorado River Authority and McCulloch Electric Cooperative, Inc. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.42		Amendment to Wholesale Power Agreement dated September 28, 1987 between Lower Colorado River Authority and McCulloch Electric Cooperative, Inc. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.43		Director Compensation Plan of the Company (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.44		Trust Agreement for the Cooperative Supplemental Executive Deferred Compensation Retirement Plan (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.45		CFC Secured Revolving Line of Credit Agreement dated June 24, 1997 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.46		Achievement Based Compensation Contract, Merger or Acquisition with Other Electric Utilities dated June 29, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.47		Agreement to Combine McCulloch and Cap Rock Electric Cooperatives dated June 30, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.48		Management Service Agreement between Cooperative and Lamar Electric Cooperative Association (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.49		Notice of Annual Meeting and Proxy Statement for Members of McCulloch Electric Cooperative held on August 21, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.50		Agreement to Combine Lamar and Cap Rock Electric Cooperatives dated October 28, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.51		Loan Agreement between New West Resources, Inc, Cap Rock Electric Cooperative, Inc. and Bank United Texas FSB dated July 12, 2000 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.52		Unconditional Guaranty from Cap Rock Electric Cooperative to Bank United Texas FSB dated July 12, 2000 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01) (1)
Exhibit 10.53		Lamar County Electric Cooperative Association Notice of Special Meeting and Proxy Statement for Special Meeting held December 14, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.54		Signature Leasing, Inc. Master Lease Agreement dated April 1, 2000 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.55		Personal Services Agreement between Leonard S. Herring and the Cooperative dated December 16, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.56		Term Loan Agreement between Eddins-Walcher Company, Frank’s Fuels, United Fuel & Energy Corporation, and New West Resources dated July 12, 2000 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.57		NewCorp Resources Electric Cooperative Open Access Transmission Tariff (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.58		Supplement to the Restated Mortgage and Security Agreement between the Cooperative

		and CFC dated May 17, 1990 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.59		Loan Agreement between Cap Rock Cooperative Finance Corporation and CFC dated June 22, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.60		Confirmation Letter between Electric Clearinghouse, Inc. and the Cooperative dated May 27, 1999 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.61		Service Agreement Rate Schedule WP between NewCorp Resources and Cap Rock Electric Cooperative dated March 31, 1995 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.62		Transaction Agreement dated as of September 9, 1993 between Southwestern Public Service Company, the Cooperative and OTP, Inc. (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.63		Assignment of Certificate of Convenience and Necessity by the Cooperative to NewCorp Resources dated January 17, 1996 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.64		Supplemental Agreement between NewCorp Resources and the Cooperative dated April 25, 1995 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(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 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.66		Assignment of Wholesale Power Contract from the Cooperative to NewCorp Resources dated March 3, 1995 (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 10.67		QSE and Ancillary Services Agreement between the Cooperative and Garland Power and Light dated June 1, 2001 (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (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 dated September 1, 2001 (originally filed with Post Effective Amendment No. to Form S-1 dated 12/31/01) (1)
Exhibit 10.70		Employment Contract between the Company and Ronald W. Lyon(originally filed with Post Effective Amendment No. 1 to Form S-1 dated 12/31/01) (1)
Exhibit 10.70a		Employment Contract between Cap Rock Energy Corporation and Ronald Lyon dated October 24, 2001 (2)
Exhibit 10.71		Employment Contract between the Company and Sam Prough dated September 14, 2001 (originally filed with Post Effective Amendment No. to Form S-1 dated 12/31/01) (1))
Exhibit 10.72		Achievement Based Compensation Agreement Corporate Asset Non-CFC Financing Arrangements dated August 21, 2001 (originally filed with Post Effective Amendment No. 1 to Form S-1 dated 12/31/01) (1)
Exhibit 10.73		Letter from State Securities Board of the State of Texas dated December 6, 2001 (originally filed with Post Effective Amendment No. 1 to Form S-1 dated 12/31/01) (1)
Exhibit 10.74		Employment Contract between the Company and Celia A. Zinn dated September 20, 2001 (originally filed with Form 10-K for period ended 12/31/02 dated 4/10/03) (1)
Exhibit 10.75		Cap Rock Energy Corporation Shareholders’ Trust (originally filed with Form 10-K for period ended 12/31/02 dated 4/10/03) (1)
Exhibit 10.76		Cap Rock Energy Corporation Trust Share Option Agreement (originally filed with Form 10-K for period ended 12/31/02 dated 4/10/03) (1)
Exhibit 10.77		Cap Rock Energy Corporation Trust Funding Agreement (1)
Exhibit 10.78		Supplemental Executive Deferred Compensation Retirement Plan dated November 14, 2002 (originally filed with Form 10-K for period ended 12/31/02 dated 4/10/03)(1)
Exhibit 10.79		Beal Bank Loan Agreements dated September 8, 2003 (originally filed with Form 10-Q for the period ended 9/30/03 dated 11/13/03) (1)
Exhibit 10.80		Washington Mutual Modification and Extension Agreement dated October 9, 2003 (originally filed with Form 10-Q for the period ended 9/30/03 dated 11/13/03) (1)
Exhibit 10.81		Achievement Based Compensation Contract, Southwestern Public Service Company Contract dated October 27, 992 (originally filed with Form 10-K for the period ended 12/31/03 dated March 30, 2004)(2)
Exhibit 10.82		Managed Services Agreement with Delinea Corporation dated March 12, 2003 (2)
Exhibit 10.83		Master Operation, Maintenance and Administrative Services Agreement dated September 29, 2003 between Cap Rock Energy Corporation and NewCorp Resources Electric Cooperative, Inc. (2)
Exhibit 10.84		Stock Acquisition Agreement between New Corp Resources Electric Cooperative, Inc. and United Fuel and Energy Corporation dated March 18, 2004 (2)

Exhibit 14.1		Cap Rock Energy Corporation Code of Ethics dated December 2, 2003 (2)
Exhibit 18.1		Change in Accounting Principle Letter from KPMG LLP (originally filed with Form 10-Q dated 5/15/03)(1)
Exhibit 20.1		Election Form (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(1)
Exhibit 21.1		Subsidiaries of the Company (originally filed with Amendment No. 1 to Form S-1 dated 3/20/01)(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 23.3		Consent of Bolinger, Segars, Gilbert & Moss, L.L.P. (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 23.4		Consent of Looper Reed & McGraw (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
Exhibit 31.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of David W. Pruitt (2)
Exhibit 31.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 of Lee D. Atkins (2)
Exhibit 32.1		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 32.2		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 Form 10K to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, Texas, on March 29, 2004.

	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	March 29, 2004
David W. Pruitt	Chief Executive Officer

*	Senior Vice President, Chief Financial Officer and Treasurer	March 29, 2004
/s/ Lee D. Atkins

*	Co-Chairman of the Board	March 29, 2004
/s/ Russell E. Jones

*	Director	March 29, 2004
/s/ S. D. Buchanan

*	Director	March 29, 2004
/s/ Floyd L. Ritchey

*	Director	March 29, 2004
/s/ Michael D. Schaffner

*	Director	March 29, 2004
/s/ Newell W. Tate

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, 2003	$	50	$	113	$	85	$	78
December 31, 2002	$	202	$	113	$	265	$	50
December 31, 2001	$	292	$	107	$	197	$	202

INDEX TO FINANCIAL STATEMENTS

Independent Auditors’ Report, KPMG LLP

Report of Independent Public Accountants, Arthur Andersen LLP

Consolidated Statements of Operations
Years ended December 31, 2003 and 2002, and nine months ended December 31, 2001

Consolidated Balance Sheets
December 31, 2003 and 2002

Consolidated Statement of Equity
Years ended December 31, 2003 and 2002, and nine months ended December 31, 2001

Consolidated Statements of Cash Flows
Years ended December 31, 2003 and 2002, and nine months ended December 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 accompanying consolidated balance sheets of Cap Rock Energy Corporation and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. The December 31, 2001, consolidated financial statements were audited by other auditors who have ceased operations and whose report, dated March 29, 2002, expressed an unqualified opinion on those consolidated financial statements.

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 misstatements. 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 Cap Rock Energy Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, the Company changed its method of accounting for unbilled revenue in 2003.

	KPMG LLP


Midland, Texas
March 29, 2004

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.

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.

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,						NINE MONTHS ENDED DECEMBER 31,
	2003			2002			2001
	Successor			Successor			Predecessor
	(Thousands of dollars except share and per share amounts)
Operating Revenues:
Electric sales	$	81,402		$	73,335		$	52,326
Other	1,450			1,302			796
Total operating revenues	82,852			74,637			53,122

Operating Expenses:
Purchased power	36,578			36,433			28,194
Operations and maintenance	10,476			7,327			5,828
General and administrative	6,471			7,144			3,326
Depreciation and amortization	7,787			6,134			4,568
Property taxes	1,345			1,367			997
Impairment of Lamar combination costs (Note 5)	—			1,357			—
Other	326			202			229
Total operating expenses	62,983			59,964			43,142

Operating Income	19,869			14,673			9,980

Other Income (Expense):
Allocation of income from associated organizations	530			478			1,205
Interest expense, net of capitalized interest	(6,979		)	(7,103		)	(8,004		)
Interest and other income	788			1,027			1,161
Loss on sale of MAP stock	(1,056		)	—			—
Equity earnings in MAP (Notes 9 and 24)	144			115			88
Total other income (expense)	(6,573		)	(5,483		)	(5,550		)

Income before income taxes	13,296			9,190			4,430
Income tax expense	2,098			414			—

Net Income	$	11,198		$	8,776		$	4,430

Net income per common share:
Basic	$	7.69		$	6.74
Diluted	$	7.41		$	6.74

Weighted average number of shares outstanding:
Basic	1,455,443			1,302,355
Diluted	1,510,741			1,302,355

Pro forma Basic and Diluted Earnings Per Share (Unaudited):
Net income per share							$	3.40
Pro forma shares outstanding							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,
	2003			2002
	Successor			Successor
	(Thousands of dollars)
ASSETS

Current Assets:
Cash	$	12,170		$	9,899
Restricted cash investment	14,169			—
Accounts receivable:
Electric sales, net	8,500			4,680
Other	371			380
Current notes receivable (Note 8 and 14)	1,250			12,490
Purchased power subject to recovery	—			3,501
Other current assets (Note 7)	1,587			8,735
Total current assets	38,047			39,685

Utility plant, net (Note 9)	152,162			156,517
Investments and notes receivable (Note 8)	10,045			12,490
Nonutility property, net (Note 10)	1,545			1,564
Other assets and deferred charges (Note 11)	1,190			1,038
Total Assets	$	202,989		$	211,294

LIABILITIES AND EQUITY

Current Liabilities:
Current portion of long-term debt	$	4,654		$	33,924
Short-term note payable	14,169			—
Accounts payable:
Purchased power	2,798			3,381
Other	2,679			1,796
Equity redemption credits (Note 2)	—			732
Purchased power cost subject to refund	203			—
Accrued and other current liabilities (Note 15)	3,902			3,066
Current income tax payable (Note 24)	562			414
Total current liabilities	28,967			43,313

Long-Term Debt, Net of Current Portion:
Mortgage notes (Note 12)	143,188			147,744
Note payable and other capital leases (Note 14)	184			308
Total long-term debt	143,372			148,052

Deferred Credits (Note 17)	3,677			5,191

Stockholders’ Equity:
Preferred stock, par value $1 per share, 50,000,000 shares authorized, no shares issued or outstanding	—			—
Common stock, par value $.01 per share, 50,000,000 shares authorized, 1,302,355 shares issued and outstanding at December 31, 2002 and 1,650,395 issued and 1,567,725 outstanding at December 31, 2003	17			13
Paid in capital	11,641			5,949
Retained earnings	19,974			8,776
Less Deferred compensation	(3,826		)	—
Less Treasury stock of 82,670 shares	(833		)	—
Total stockholders’ equity	26,973			14,738
Total Liabilities and Stockholders’ Equity	$	202,989		$	211,294

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
									Total			Patronage			Other			Patronage Capital Obligated to be		Total Margins
	Common Stock			Paid in			Retained		Stockholders’			Capital			Equities and			converted to		and
	# shares	Value		Capital			Earnings		Equity			Credits			Margins			Shareholder Equity		Equities
Balance, March 31, 2001												$	15,480		$	(9,805	)			$	5,675
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		—
Net income for nine months												—			4,430					4,430
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.

(continued)

F - 6

	(Thousands of dollars except number of shares)
	Successor
	Common Stock				Paid in Capital			Retained Earnings		Deferred Compensation			Treasury Stock					Total Stockholders’ Equity
	# shares		Value		Paid in Capital			Retained Earnings		Deferred Compensation			# of Shares		Value			Total Stockholders’ Equity
Balance, December 31, 2002	1,302,355		13		5,949			8,776										14,738
Repurchase of shares through tender offer													(82,140	)	(821		)	(821		)
Stock awarded through Stock Incentive Plan, net of shares withheld for taxes and amortization of deferred compensation	348,940		4		5,720					(3,826		)						1,898
Unvested shares forfeited	(900	)			(9		)											(9		)
Repurchase of vested shares issued through stock incentive plan													(260	)	(9		)	(9		)
Adjustment to original converson distribution					(19		)						(270	)	(3		)	(22		)
Net income								11,198										11,198
Balance, December 31, 2003	1,650,395		$	17	$	11,641		$	19,974	$	(3,826	)	(82,670	)	$	(833	)	$	26,973

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

F - 7

CAP ROCK ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	YEAR ENDED DECEMBER 31,						NINE MONTHS ENDED DECEMBER 31,
	2003			2002			2001
	Successor			Successor			Predecessor
	— — — — — (Thousands of dollars)— — — — —
Cash Flows From Operating Activities:
Net income	$	11,198		$	8,776		$	4,430
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,772			9,253			8,328
Noncash deferred compensation expense	2,020			—			—
Write off of investments in proposed acquisitions	—			1,357			—
Equity earnings in Map	(144		)	(115		)	(88		)
Loss on equity method investment value	1,056			—			—
Change in:
Other assets/deferred credits	(2,964		)	5,909			17
Accounts receivable	(3,811		)	(921		)	2,370
Purchased power cost subject to refund	3,704			(3,888		)	(3,808		)
Other current assets	(1,059		)	(6,386		)	(926		)
Accounts payable and accrued expenses	1,284			(735		)	934
Net cash provided by operating activities	22,056			13,250			11,257
Cash Flows From Investing Activities
Utility plant additions	(5,209		)	(1,517		)	(4,257		)
Proceeds from liquidation of investments	1,511			1,043			(76		)
Issuance of notes receivable	(1,250		)	—			—
Collection of notes receivable	12,490			1,000			2,100
Net cash provided by (used in) investing activities	7,542			526			(2,233		)
Cash Flows From Financing Activities:
Net borrowings under lines of credit	—			—			40
Proceeds from other long-term debt and capital leases	14,169			534			—
Payments on mortgage notes	(3,704		)	(3,034		)	(2,320		)
Payments on other long-term debt and capital leases	(30,246		)	(6,387		)	(4,377		)
Restricted cash investment	(5,962		)	—			—
Repurchase/acquisition of common stock	(852		)	—			—
Retirement of former member equity	(732		)	(488		)	(2,605		)
Net cash used in financing activities	(27,327		)	(9,375		)	(9,262		)
Increase (Decrease) in Cash and Cash Equivalents:	2,271			4,401			(238		)
Cash at beginning of period	9,899			5,498			5,736
Cash at end of period	$	12,170		$	9,899		$	5,498
Noncash financing activities:
Deferred compensation related to stock awards	$	3,695		—			—
Supplemental Cash Flow Information
Cash paid during the period for interest	$	6,640		$	8,611		$	8,320
Cash paid during the period for income taxes	1,950			—			—

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

F - 8

CAP ROCK ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2003, 2002, AND 2001

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cap Rock Energy Corporation, Inc. (the “Company” or 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 Cooperative was incorporated as an electric cooperative in the State of Texas in 1939 to provide electric distribution services and power to its members. The Company currently provides service to approximately 35,000 meters in 28 counties covering approximately 13,000 square miles in Texas. Its customers, which are principally residential, ranching and oil and gas, 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, is also engaged in the transmission of electricity through a looped system 305 miles in length, and in providing various electric and nonelectric services to customers.

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, Petra One Energy, L.P., Petra Energy, LLC 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. The Predecessor’s consolidated financial statements include the accounts of the Cooperative and its wholly-owned subsidiaries, Energy, 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 dissolved and all remaining assets and liabilities were transferred to NewCorp. The Cooperative was dissolved in March 2004. Energy and NewCorp maintain accounting records in accordance with the uniform system of accounts, as prescribed by the Federal Energy Regulatory Commission (“FERC”).

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.

Use of Estimates

The preparation of the Company’s consolidated financial statements, in conformity with generally accepted accounting principles, requires management to make estimates and assumptions with respect to values or conditions which cannot be known with certainty, that affect the recorded amounts of assets and liabilities, disclosure of contingent assets and liabilities and the recorded amounts of revenues and expenses. Actual results could differ from those estimates. Items which may be estimated include, but are not limited to, the economic useful lives of assets, fair value of assets and liabilities, impairment of goodwill, obligations under employee benefit plans, valuation allowances for receivables and deferred tax assets, unbilled revenues for distribution services and electricity provided for which meters have not been read, and various other recorded or disclosed amounts.

Regulatory Accounting

The Company’s principal business is the transmission and distribution of electricity through NewCorp and Energy, respectively. NewCorp is subject to regulation by the Federal Energy Regulatory Commission, and Energy is now regulated by the Public Utility Commission of Texas (“PUCT”). Accordingly, the Company accounts for the effects of regulation pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This statement applies to the financial statements of an entity that has rates that (1) are approved by a body empowered to set rates that bind customers, (2) are cost-based, and (3) can be charged to and

F - 9

collected from customers. If an entity meets the above three criteria, it is required to capitalize costs that would otherwise be charged to expense if the actions of the regulating body make it probable that those costs will be recovered through rates in future periods. These capitalized costs are classified as regulatory assets. SFAS No. 71 also requires the rate-regulated entity to assess the recoverability of regulatory assets reflected on its balance sheet.

At December 31, 2003, there were two regulatory liabilities, purchased power cost subject to refund, of $203,000, and $704,000 related to excess recovery of costs incurred in connection with the transfer of the Certificate of Convenience and Necessity. See also Note 23. These are expected to be refunded to customers or earned within 12 months. At December 31, 2002, the Company had one regulatory asset which was a purchased power cost recovery receivable of $3,501,000, and a regulatory liability which was deferred revenue of $2,182,000. These items were recovered or recognized within 12 months.

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 year ended December 31, 2001, has been included for the Predecessor as shown in Note 4.

Earnings Per Share

Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding. Diluted earnings per common share is computed by dividing net income by the weighted average number of common shares plus the dilutive impact of stock options, warrants and deferred compensation arrangements which were outstanding during the period calculated by the treasury stock method.

Pro Forma Earnings Per Share (Unaudited)

Pro forma basic and diluted earnings per share (unaudited) are presented in the accompanying consolidated statement of operations for the nine months ended December 31, 2001. Pro-forma basic and diluted earnings per share are based on the assumption that, on April 1, 2001, 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. As discussed in Note 2, such conversion occurred in February 2002.

Cash and Cash Equivalents

The Company considers all unrestricted 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.

Restricted Cash Investment

The Company is required to maintain a restricted cash investment of $14,169,000 which serves as collateral for the initial advance from Beal Bank S.S.B. Terms of the loan agreement provide for investment of the cash collateral only in certain specified types of investments. Interest earned is not restricted, and is not classified as restricted. See Note 13.

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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, 2003 and 2002, the allowance for doubtful accounts was $78,000 and $50,000, respectively. Bad debt expense for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, was $113,000, $120,000, and $102,000, respectively.

Inventories

Although the Company has outsourced its materials warehousing function to an outside third party, inventories owned and on hand are primarily transmission parts and materials which are not normally stocked by the warehousing company; supplies and materials maintained on service trucks; and materials at various remote field locations. Inventories are valued at historical cost, at the lower of cost or market.

Investments and Notes Receivable

The Company 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. Investments accounted for under the cost method are recorded at their initial cost, and any dividends or distributions received are recorded in income. For equity method investments, the Company records its share of earnings or losses of the investee during the period. Recognition of losses will be discontinued when the Company’s share of losses equals or exceeds its carrying amount of the investee plus any advances made or commitments to provide additional financial support.

The Company has investments in associated organizations that relate primarily to required membership certificates and accumulated capital allocations, all of which are accounted for using the cost method of accounting. Capital allocations for the two primary investees, National Rural Utilities Cooperative Finance Corporation (“CFC”) and Texas Electric Cooperative, Inc. (“TEC”), are determined annually by the respective organizations based on its bylaws, operating margins, cash positions and other factors. The Company recognizes equity allocations from the respective organization as income when it is declared by each respective organization. CFC is the Company’s primary lender and TEC provides various lobby services for electric cooperatives in Texas.

The Company previously had investments in oil and gas royalty interests. As discussed in Note 8, 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”) and accounted for its investment in MAP under the equity method of accounting. The MAP investment was sold October 2003.

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. Contributions in aid of construction are credited to the applicable utility plant accounts. 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 cost of maintenance, repairs and minor replacements are charged to operations as incurred. The Company does not accrue any cost in advance for major maintenance or repair projects or the cost of removal.

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

Transmission plant		10 - 33 years
Distribution plant		32 years
General plant:
Structure and improvements		10-40 years
Transportation		3 years
Equipment		3 years
Other		5-7 years

Nonutility Property

Nonutility property is real estate, primarily an office building, and investments in real estate partnerships not principally used in the Company’s core business of electric distribution. All nonutility property except real estate partnerships is stated at original cost. Maintenance, repairs and miscellaneous replacements and renewals of this type 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. The investments in real estate partnerships are accounted for under the cost basis method of accounting because the Company’s ownership is less than 10% in each case.

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.

Goodwill and Intangible Assets

Goodwill is the excess of purchase price over the fair value of the net assets acquired. The Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” effective January 1, 2002. Under SFAS No. 142, goodwill is reviewed annually for impairment or whenever events and changes in circumstances occur that may reduce the fair value below the carrying value. Evaluation of fair value takes into 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 the recorded goodwill has exceeded the carrying value. Prior to the Company’s adoption of SFAS No. 142, goodwill was amortized on a straight-line basis over 60 months.

In connection with the conversion of the line of credit with CFC into a long term mortgage note, the Company was required to pay a conversion fee. This is being amortized over the life of the new debt, which is 6 years.

The Company capitalized costs it incurred in connection with the financing arrangements with Beal Bank S.S.B. The terms of the initial advance with the bank provide for a due date of September 9, 2004, and because it is not certain that the Company will draw on the additional advance, the financing costs are being amortized over the 12 month period of the initial advance. See also Note 13.

The Company has other miscellaneous intangible assets that are not deemed to have indefinite lives. These assets will continue to be amortized over their estimated useful lives, which range from 3 to 10 years. See Note 11.

Deferred Revenue

Deferred revenue is included in Deferred Credits on the balance sheet (see Note 17), and represented power costs expensed in prior periods that was billed to customers and recognized as revenue in subsequent periods.

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Capitalized Interest

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

Equities and Margins of the Cooperative

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, in accordance with the Cooperative’s conversion plan, the Cooperative repurchased certain members’ equity account balances aggregating approximately $2,181,000, at a discounted cash price of $1,524,000. 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 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, in accordance with the Cooperative’s conversion plan, the Cooperative repurchased certain members’ patronage capital credit balances aggregating $909,000 by issuing electric credits of the same respective amount 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 December 31, 2002, the Company recorded revenue on the basis of meters read and billed to customers. This was pursuant to the rate-making policy as set by the Company’s Board of Directors. The accrual method recognizes revenue when the service and power have been delivered to the customer. Had the Company recorded revenue on an accrual basis, a regulatory liability would have existed because it was 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.

Effective January 1, 2003, the Company’s Board of Directors revised the rate-making policy to recognize unbilled revenue. Therefore, the Company was required to change accounting principles. Under the new rate-making structure, the Company records revenue based on amounts billed to customers as well as unbilled amounts based upon an estimate of the revenues for energy and service delivered since the latest billing through the end of the period. The effect of the change was to increase electric revenues by $3,400,000 and increase purchased power by $1,318,000, for a net increase in income before income taxes of $2,082,000.

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

Other revenue consists primarily of building rental income and is accrued monthly based on contractual lease obligations.

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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 collect actual purchased power costs incurred in providing service. In September 2001, the Company determined that approximately $1,700,000 of collected power recovery costs subject to refund represented billable costs to customers 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. In 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 future billings to customers over a 24 month period beginning in January 2002 and ending in December 2003. This created a regulatory asset, purchased power costs subject to recovery, and a regulatory liability, deferred revenue. See Note 17.

Stock Based Compensation

Effective January 1, 2003, the Company adopted the fair value method of accounting for its employee stock incentive plan in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation, Transition and Disclosure.” Under the historical or retroactive transition method allowed by SFAS No. 148, the compensation expense for the year ended December 31, 2002, would not have been different had the fair value method been originally applied. See also Note 16.

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). Upon conversion to a shareholder owned business corporation, the activities and transactions formerly performed by the Cooperative became taxable. 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.

Derivative Instruments

The Company may use derivative instruments to manage the natural gas component of power costs, which minimize the fluctuations in customers’ power bills. All payments made or received in connection with these types of transactions will be collected from or rebated to 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. As of December 31, 2003, no derivative portfolio was held.

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New Accounting Standards

Effective January 1, 2003, the Company adopted SFAS No. 143, “Asset Retirement Obligations,” which addresses the financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The implementation of this standard did not have a material impact on the Company’s financial position or results of operations.

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In April 2003, the FASB issued Statement No. 149 (“SFAS No. 149”), “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting requirements for derivative instruments, including derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In general, SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. Adoption of this statement did not have a material impact on the Company’s financial position or results of operations.

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 the 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. The Cooperative was dissolved in March 2004.

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. The Cooperative accepted all Dutch auction bids of 70% or less of stated capital credit account balances received from members. The difference between the stated capital credit account balances and the discounted Dutch Auction cash price was credited to the Cooperative’s Other Equity account. As of December 31, 2001, the equity retirement payable had been fully paid. 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.

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Energy 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 3 concerning the Company’s related repurchase offer.

Those Cooperative members who opted to receive electric credits equal to 100% of their equity account balances received those credits ratably over a 24-month period beginning October 2001. The unamortized balance of equity redemption credits at December 31, 2002, was $732,000, and at December 31, 2003, all credits had been applied to customer’s balances.

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.

3. REPURCHASE 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 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 made the offer to all shareholders and extended the offering period beyond the original 60 days. The offering period began February 5, 2003, and ended April 30, 2003, with 82,140 shares of common stock tendered to and accepted by the Company at $10 per share, totaling $821,400. At December 31, 2003, such amount is shown in Treasury stock within the Stockholders’ Equity section of the consolidated balance sheet. There are no further obligations related to the Company’s repurchase commitment.

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4. COMPARABLE STATEMENT OF OPERATIONS (UNAUDITED)

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

	YEAR ENDED DECEMBER 31, 2001
	Predecessor (Unaudited)

Total operating revenues	$	73,412

Purchased power	40,781
Operations and maintenance	7,427
General and administrative	4,664
Depreciation and amortization	6,159
Property taxes	1,380
Other	310
Total operating expenses	60,721

Operating income	12,691

Interest expense	(10,818		)
Other income items	2,961
Net income	$	4,834

5. UNSUCCESSFUL 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. Lamar filed suit against the Company seeking a declaratory judgment that it had the right to terminate both agreements without regard to payment of any kind to the Company. 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 previously capitalized costs that were incurred in connection with the combination. The majority of these costs were outside legal and consulting fees. At December 31, 2002, these costs, aggregating $1,357,000 were expensed and are shown on the consolidated statement of operations.

6. EARNINGS PER SHARE INFORMATION

The following table shows the reconciliation of basic and diluted earnings per share:

	YEAR ENDED DECEMBER 31, 2003
	Income		Shares	Per Share
	(In Thousands)
Basic earnings per share:
Income from continuing operations available for common stock	$	11,198	1,455,443	$	7.69

Effect of diluted securities:
Shares that have been deferred under the Stock for Compensation plan			55,298

Diluted earnings per share:	$	11,198	1,510,741	$	7.41

Both basic and diluted earnings per share for the year ended December 31, 2002, are not materially different. The proforma basic and diluted earnings per share for the nine months ended December 31, 2001, are the same.

7. OTHER CURRENT ASSETS

Other current assets as of December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003		2002

Capital lease sinking fund (Note 13)	$	—	$	7,395
Inventories	939		930
Prepaid insurance	385		335
Interest receivable	67		58
Other	196		17
Total Other Current Assets	$	1,587	$	8,735

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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 was due in 2003. In prior periods, the balance of the capital lease sinking fund was shown in Other Assets.

8. INVESTMENTS AND NOTES RECEIVABLE

Investments and notes receivable as of December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003		2002
Investments in associated organizations:
CFC capital term certificates	$	6,210	$	6,304
CFC patronage capital	2,543		2,519
TEC patronage capital and bonds	852		852
Other	49		73
Total investments in associated organizations	9,654		9,748

Investment in United Fuel (Note 14)	360		360
Investment in MAP	—		2,162
Other investments	31		220
Total Investments and Notes Receivable	$	10,045	$	12,490

Allocations of income from all associated organizations was $530,000, $478,000 and $1,205,000, respectively, for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001.

The Company owned approximately 42% of MAP and accounted for its investment using the equity method. Effective October 8, 2003, the Company reached an agreement with MAP to sell its shares of stock in exchange for a note receivable of $1,250,000, due October 8, 2004, with interest at 6% per annum. The note receivable, shown in Current Notes Receivable, is collateralized by the original stock. The investment appreciated over the period that the Company held it, but because the sales price was less than the recorded book value on an equity method basis, the Company was required to reflect a loss of $1,056,000. Upon receipt of the proceeds from the note receivable, the Company will have recouped its original cash investment. The Company’s equity earnings in MAP for the nine month period ended September 30, 2003, the year ended December 31, 2002, and the nine months ended December 31, 2001, was $144,000, $115,000 and $88,000, respectively.

In March 2004, the Company signed an agreement with a shareholder of United Fuel to sell its shares of stock at a sales price of $1,300,000. Consummation of the sale is contingent upon certain future events, such as United Fuel’s capitalization arrangements. It is unknown when those events will transpire.

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9. UTILITY PLANT

Utility plant as of December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003			2002

Transmission facilities	$	69,051		$	63,943
Distribution facilities	179,250			177,678
General facilities	9,045			10,456
Total utility plant	257,346			252,077
Less accumulated depreciation	(105,349		)	(95,785		)
Total utility plant in service, net	151,997			156,292
Construction work in progress	165			225
Total Utility Plant, net	$	152,162		$	156,517

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

10. NONUTILITY PROPERTY

Nonutility property as of December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003			2002

Real estate	$	2,278		$	2,257
Furniture, fixtures, and other	7			7
Total nonutility property	2,285			2,264
Less accumulated depreciation	(740		)	(700		)
Total Nonutility Property, net	$	1,545		$	1,564

The Company owns a 45,000 square foot office building that is used as its general corporate headquarters. The Company currently occupies approximately 35% of the building and the remainder is leased to commercial tenants, subject to leasing terms ranging from monthly to 7 years. For the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, third party building rental revenue was $258,000, $286,000, and $244,000, respectively. Building rental revenues, which are not material to the Company’s operations, for each of the next five years are expected to be approximately $250,000 per year. As of December 31, 2003 and 2002, the net book value of the building and related property was $1,141,000 and $1,161,000, respectively, which is the majority of the nonutility property.

The Company sold its investments in real estate partnerships in February 2004, to an unrelated third party in exchange for a note receivable of $286,000 due 2009, with an interest rate of 4.5% per annum. There was no gain or loss recorded on the sale. The note is collateralized by the partnership interests. In prior years, the Company had guaranteed debt of some of the partnerships, with the maximum exposure of such guarantees aggregating $5,178,000 at December 31, 2003. The sale of the partnership interests also involved the transfer of those guarantees to the buyer. Income for each period shown related to the real estate partnerships has been less than $12,000.

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11. OTHER ASSETS AND DEFERRED CHARGES

Other assets as of December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003		2002
Capital lease acquisition cost, net of amortization (Note 13)	$	—	$	735
McCulloch goodwill, net of amortization	199		199
Bank fees, net of amortization (Notes 12 and 13)	846		—
Other	145		104
Total Other Assets and Deferred Charges	$	1,190	$	1,038

The McCulloch goodwill represents costs incurred in connection with the acquisition of an electric cooperative in 1999, in the amount of $373,000. As of December 31, 2003 and 2002, the accumulated amortization was $174,000.

The bank fees are costs incurred in connection with the conversion of the line of credit to a mortgage note, as well as the refinancing of the transmission system with Beal Bank, S.S.B. Accumulated amortization at December 31, 2003, aggregated $363,000, with none recognized as of December 31, 2002. See also Notes 12 and 13.

12. 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, which 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.

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	DECEMBER 31,
	2003			2002
Interest at 3.35% at December 2002 and 2003, with interest repricing in January 2004 and 2005	$	10,400		$	11,525
Interest at 4.20% with interest repricing in January 2005	69,109			70,519
Interest at 4.70% with interest repricing in January 2006	34,128			35,189
Interest at 4.50% with interest repricing in January 2007	6,080			—
Interest at 4.30%	28,000			28,000
Interest at fixed rates:
6.50%	—			6,188
7.00%	2			3
	147,719			151,424
less current maturities	(4,531		)	(3,680		)
Total mortgage debt, net of current portion	$	143,188		$	147,744

In October 2002, CFC agreed to convert the Company’s line of credit, aggregating $28,000,000, to a long term mortgage note, collateralized by distribution assets, with quarterly principal 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. Interest is at 4.30% per annum and payments are due quarterly. There was also a fee of $210,000 associated with the conversion.

The Company has capitalized, as a part of utility plant, the cost of borrowed funds used for financing construction. Capitalized interest for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, was $7,000, $12,000, and $31,000, respectively. The rate used for interest charged to construction is the Company’s effective borrowing rate.

Annual maturities of the mortgage notes as of December 31, 2003, are as follows (in thousands):

2004	$	4,531
2005	8,330
2006	4,586
2007	4,721
2008	28,430
Thereafter	97,121

Total mortgage debt	$	147,719

13. TRANSMISSION SYSTEM FINANCING

In connection with the original financing and construction of its transmission line, the Company entered into agreements with Southwestern Public Service Company (“SPS”), Metropolitan Life Insurance Company, and John Hancock Leasing Corporation. These agreements qualified as capital lease obligations with reversionary features and, as a result, the transmission line, substation assets and associated capital lease obligations were recorded on the Company’s consolidated financial statements.

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The original cost of the transmission facility and costs related to consummation of the lease agreements totaled $61,999,000, and were being recovered from customers through power cost billings over a ten year period. Consistent with this ratemaking treatment, the transmission facilities and capital lease obligation were being amortized over the same ten year period, with that period ending September 30, 2003. The monthly lease payments included an amount for a sinking fund, which was to be used to reduce the amount of the final balloon payment on the capital lease. The final balloon payment of $14,076,000 was due September 2003.

Regularly scheduled monthly principal payments on the transmission system capital lease obligation for the nine months ended September 30, 2003, year ended December 31, 2002, and nine months ended December 31, 2001, were approximately $3,556,000, $5,047,000, and $3,577,000, 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.

Interest on the capital lease obligations for the nine months ended September 30, 2003, year ended December 31, 2002, and the nine months ended December 31, 2001, was approximately $847,000, $1,443,000, and $1,305,000, respectively, and is classified as purchased power cost consistent with ratemaking treatment.

The lease payments included an amount for a sinking fund, which was to 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 Note 7.

The initial advance was completed in September 2003. Simultaneously, the original lien on the transmission system was released and the sinking fund of $8,207,000 was transferred to a restricted securities account. NewCorp added $5,962,000 to the restricted securities account to bring the total restricted cash investment to $14,169,000, the amount of the initial advance proceeds. This restricted cash investment is the only asset collateralized by Beal Bank in connection with the initial advance. Terms of the loan agreement provide for investment of the cash collateral only in certain specified types of investments. Upon funding of the additional advance, the restricted cash investment would be released, and the transmission system, receivables and other assets related to the transmission system would be the collateral for the full loan. The loan is non-recourse to Cap Rock Energy.

Interest on the Beal Bank loan is the greater of 10.75% per annum, or 7% plus the one-month LIBOR rate, payable monthly. The initial advance amount of $14,169,000 is due September 9, 2004, unless the additional advance is funded on or before that date, in which case, the entire principal amount would be payable monthly amortized over 15 years. Pursuant to the terms of the financing arrangement, prepayment of the initial advance is not allowed before its scheduled maturity date; prepayment of the additional advance would not be allowed for the first 24 months of the loan period, with a 1% fee if prepayment was made during months 25 through 48. The financing arrangement also provided for a commitment fee of 2% of the total loan amount, with $457,000 payable for the initial advance, and the remaining $173,000 payable for the additional advance. Additional customary fees payable to Beal Bank were for reimbursement of expenses, attorneys fees, appraisals and consulting, which at December 31, 2003, aggregated $999,000. Maintenance of certain financial covenants would be required upon funding of the additional advance, and the Company and

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NewCorp are already in compliance with such future requirements. The Company would be required to maintain consolidated net worth of $5,000,000 and NewCorp would be required to maintain a ratio of net income plus interest, taxes, depreciation and amortization to debt service of at least 1.2 to 1.0 on a rolling quarter basis.

14. NOTE PAYABLE AND OTHER CAPITAL LEASES

In July, 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 was shown entirely in Current portion of long-term debt because it was due in 2003. The loan agreement required monthly payments based on a fifteen-year amortization with interest at Wall Street Journal prime rate plus 1%, which, at December 31, 2002, was 5.25%. Simultaneously, the Cooperative loaned $15 million to two fuel and lubricant subsidiaries of United Fuel and Energy Corporation (“United Fuel”) 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 had 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 was shown entirely in Current portion of notes receivable because it was due in 2003. 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% 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 had a right to acquire an additional 10% ownership in United Fuel, subject to certain parameters. 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. See Note 8.

In October 2003, United Fuel consummated financing with a lender that provided for funds to partially pay down the Company’s note payable to a bank, with United Fuel taking the position as borrower on the Company’s note payable to a bank, thus extinguishing United Fuel’s note receivable to the Company. The Company is no longer a borrower and its involvement has been reduced to being a secondary guarantor for United Fuel’s note of $3,500,000. FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” requires the Company to record a guarantee obligation that is measured at fair value. The Company’s calculation of fair value included factors such as being a secondary guarantor and United Fuel’s assets collateralizing the note. The Company has calculated its exposure and recorded a guarantee obligation of $35,000 in October 2003. Upon United Fuel’s repayment of the note and the bank’s release of the guaranty, scheduled for October 2004, the Company will be able to eliminate the recorded obligation.

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The Company has other miscellaneous capital leases for certain equipment used in operations, with such equipment included in utility plant on the balance sheet. Future minimum lease payments are as follows (in thousands):

2004	$	123
2005	110
2006	57
2007	18
Total capital lease obligations	$	308

15. ACCRUED AND OTHER CURRENT LIABILITIES

Accrued and other current liabilities at December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003		2002
Accrued taxes	$	18	$	227
Accrued interest	520		479
Accrued payroll and employee benefits (Note 16)	1,670		1,530
Regulatory liability	704		—
Customer deposits and prepayments	760		752
Accrued other	230		66
Total Accrued and Other Current Liabilities	$	3,902	$	3,054

16. 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 Retirement 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. In March 2004, $16,000 was contributed to the plan, and such amount is shown as a liability on the consolidated balance sheet at December 31, 2003.

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

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be acquired by the Plan either through open market purchases or through the issuance of additional common stock. For the years ended December 31, 2003 and 2002, the Company recorded compensation expense of $2,045,000 and $30,000, respectively, in connection with these awards. These shares have not been issued or distributed. See also Note 11.

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, 2003, 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. For the years ended December 31, 2003, and 2002, cash bonuses of $6,000 and $367,000 respectively 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 percent of eligible earnings up to the maximum federal limit to various self-directed investment funds. The plan provides for various levels of Company matching contributions depending upon the level of employee contributions. Company contributions aggregated $527,000, $481,000, and $331,000 for the years ended December 31, 2003 and 2002, and the nine months ended December 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 years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, totaled $399,000, $858,000, and $227,000, respectively.

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The funded status of the plan and the amounts recognized on the balance sheet as of December 31, 2003 and 2002 are as follow (in thousands):

	DECEMBER 31,
	2003			2002
Accumulated Postretirement Benefit Obligation (APBO):
Actives not yet eligible	$	3,149		$	1,985
Actives fully eligible	1,352			724
Retirees and dependents	4,618			4,854
Total APBO	9,119			7,563
Plan assets at fair value	—			—
Accrued postretirement benefit liability	9,119			7,563
Unrecognized loss from past experience different from that assumed and from changes in assumptions	(5,611		)	(4,695		)
Accrued postretirement benefit cost	$	3,508		$	2,868

Changes in the accrued postretirement benefit cost for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, are as follows (in thousands):

	DECEMBER 31,
	2003			2002			2001
Balance, beginning of period	$	2,868		$	2,696		$	2,629
Net periodic postretirement cost	1,039			858			356
Contributions	(399		)	(686		)	(289		)
Balance, end of period	$	3,508		$	2,868		$	2,696

Net periodic postretirement benefit costs for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, are as follow (in thousands):

	DECEMBER 31,
	2003		2002		2001
Service cost	$	206	$	148	$	128
Interest cost	504		471		228
Amortization of experience loss	329		239		—
	$	1,039	$	858	$	356

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

	DECEMBER 31,
	2003		2002		2001
Discount rate	6.00	%	7.00	%	7.25	%

Medical, prescription drugs and dental cost trend rates: Beginning at 9% in 2004, grading downward by 1% per year to an ultimate rate of 5% per year in 2008.

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The assumed health care cost trends significantly affect the amounts reported for the post retirement health care liability. A one percentage point change in assumed health care cost trend rates would have the following effects for 2004 (in thousands):

	One Percentage Point
	Increase		Decrease
Effect on total of service cost and interest cost	$	124	$	(98	)
Effect on accumulated post retirement benefit obligation	1,309		(1,055		)

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

The following table provides estimates of future benefit payments, which reflect expected future service, as applicable (in thousands):

2004	$	484
2005	549
2006	563
2007	588
2008	585
2009-2013	3,103

17. DEFERRED CREDITS

Deferred credits at December 31, 2003 and 2002, consisted of the following (in thousands):

	DECEMBER 31,
	2003		2002
Post retirement benefits (Note 16)	$	3,508	$	2,868
Deferred executive compensation	44		3
Unclaimed member capital credits	67		68
Deferred revenue	—		2,182
Other	58		73
Total Deferred Credits	$	3,677	$	5,194

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 were being recovered from customers on a monthly basis over a 24 month period from January 2002 to December 2003. During 2002, the Company billed and recognized $2,182,000 of deferred revenue, with the balance of $2,182,000 recognized in 2003.

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18. 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, 2003 and 2002. 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 (in thousands):

	DECEMBER 31,
	2003				2002
	BOOK VALUE		FAIR VALUE		BOOK VALUE		FAIR VALUE
Cash	$	12,170	$	12,170	$	9,899	$	9,899
Restricted cash investment	14,169		14,169		—		—
Notes receivable	1,250		1,250		12,490		12,490
Mortgage notes	147,719		147,719		151,424		151,424
Short-term note payable	14,169		14,169		—		—

The book value of cash and the restricted cash investment 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, 2003 and 2002. 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.

19. MAJOR CUSTOMERS AND SUPPLIERS

For the years ended December 31, 2003 and 2002, and the nine months ended December 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 has also outsourced its meter reading function. In the event the contract with the third parties should not be renewed, the Company believes its operations would not be severely affected because new contracts could be secured at competitive rates and in a timely manner. See also Note 23, Commitments and Contingencies.

20. ELECTRIC DEREGULATION AND CUSTOMER CHOICE

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, provided for retail competition to begin on January 1, 2002. Municipally owned utilities and cooperatives could elect, but were not required, to offer retail customer choice on or after January 1, 2002. The Company met the definition of a “cooperative” under this legislation. On June 22, 2003, the Governor of the State of Texas signed Senate Bill 1280 into law which became effective September 1, 2003. The definition of “electric cooperative” under the Public Utility Regulatory Act (“PURA”) included a “successor to an electric cooperative created before June 1, 1999, in accordance with a conversion plan approved by a vote of the electric cooperative, regardless of whether the successor later purchases, acquires, merges with or consolidates with, other electric cooperatives.” SB 1280 amended the PURA to treat a successor to an electric cooperative as an investor owned utility. This legislation also provided for establishment of schedules and procedures by the Public Utility Commission of Texas for such a successor that was not previously subject to regulation as an investor owned utility prior to September 1, 2003, in order to comply with the requirements of

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deregulation and competition. The Company’s rates are now subject to regulation and approval by the PUCT, not the Company’s Board of Directors.

Under the new law, the PUCT will establish schedules and procedures for the Company to comply with the requirements of competition. Although management believes that House Bill 1642 concerning available customer choice shall occur no sooner than 2007 for the major service area in which the Company operates, the PUCT may issue an order to the Company for a required time frame that may be a later date, or a date sooner, than 2007. The Company believes the PUCT will be reasonable in developing such schedules and procedures and that such action will not adversely affect the Company’s customers.

21. RELATED PARTY ACTIVITY

One of the compensation vehicles utilized by the Company is the Achievement Based Contract – Southwestern Public Service Company (“ABC-SPS”). The ABC-SPS contract provides for total compensation of 2% of the annual savings derived from the SPS purchased power contract as compared to the prior Texas Utilities purchased power contract. Two executive officers are the only remaining participants in the ABC-SPS contract, which expired in October 2003. For the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, compensation attributable to the contract was $126,000, $156,000 and $48,000, respectively.

Another compensation arrangement is the Achievement Based Compensation Contract-Merger or Acquisition with Other Electric Utilities (“ABC-Merger Contract”). The terms of the ABC-Merger Contract provided for compensation to the participants equal to 1.5% of the total assets added to the Company by merger or acquisition. Total assets added means those mergers or acquisitions of electric or telephone cooperatives or municipal electric systems that require the assumption of debt and equity. Compensation under the ABC-Merger Contract is to be allocated 60% to participating executive officers, 10% to the general counsel and 30% to directors and advisory directors. The ABC-Merger Contract, amended in 2000, expires in August 2010. No amounts have been paid or accrued under the ABC-Merger Contract for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001.

The Achievement Based Compensation Agreement – Corporate Asset Non-CFC Financing Arrangements (“ABC-Power Transmission Contract”) is another compensation vehicle relating to corporate objectives. Total participant compensation will be 1.0% of the net profit or net capital acquired by the Company in connection with the sale or leaseback of the transmission system, if payment of the earned compensation is taken in the form of cash. If the participant elects to take payment in the form of common stock of the Company, the individual will be awarded shares based on twice the calculated compensation. Compensation attributable to the ABC-Power Transmission Contract will be allocated 69% to the executive officers and 31% to be allocated to the directors and former directors. No amounts have been paid or accrued under the ABC-Power Transmission Contract.

22. 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, 2003 and 2002, there were 340,738 and 344,171 shares of stock, respectively, held beneficially by the Trust. Other powers are limited to those granted in the Trust document, the Funding Agreement and the Share Option Agreement.

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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 2003 and 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. Pursuant to state law, the shares are scheduled to be escheated to the State of Texas in 2005.

23. COMMITMENTS AND CONTINGENCIES

The Company has various obligations to make future payments under contractual obligations:

	2004		2005		2006		2007		2008		Thereafter		Total
	— — — — — — — — — — — — — — (Thousands of dollars) — — — — — — — — — — — — — —
Operating lease obligations	$	314	$	97	$	79	$	42	$	27	$	25	$	584
Purchase obligations	2,314		1,837		1,837		1,837		140		811		8,776
Other long term liabilities	1,188		1,253		641		659		622		3,128		7,491

Operating leases relate primarily to equipment. Purchase obligations include IT services and power contracts. All of the Company’s power contracts are firm, full requirements contracts. These types of contracts require the Company to purchase all of its power needs from the seller, but do not mandate a minimum purchase amount. The amounts included for each year are basic required transmission charges.

The Company has entered into an agreement with a third party to provide certain information technology related managed services including assessment of the current IT environment and future needs; product selection; implementation of financial and operational IT systems; hosting of the applications in a remote environment; user and application support, as well as desktop support. Beginning March 2004, ongoing maintenance and support costs will be based on the number of meters and will approximate $1,697,000 per year through 2007. These amounts are reflected in the above table under Purchase obligations. If a termination of services occurs before the end of the contract, except for material nonperformance, the Company will be required to pay a termination fee on a decreasing sliding scale over the term of the contract. The maximum amount for such termination fee is $1,414,000.

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The Company has a contract with the City of Farmersville, Texas, to provide power to its customers and assume all related billing and collection functions. Terms provide for a two year written notification for termination by either party. The Company is obligated to make payments to the City of Farmersville on a revenue sharing type basis. The 2004 and estimated 2005 annual payments are $626,000 and are reflected in the table under Other long term liabilities.

The Company purchases all of its electric power pursuant to long-term wholesale electric power contracts with Southwestern Public Service Company, Lower Colorado River Authority (“LCRA”) and Garland Power and Light (“Garland”). SPS, LCRA and Garland contracts expire in 2013, 2016 and 2005, respectively, and account for approximately 74%, 14% and 12%, respectively, of the Company’s electric power purchases for 2003. 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 terminated, the Company’s operations will not be severely affected as new contracts can be secured at competitive rates with other electric power providers. However, all costs associated with purchased power are passed through to the retail customer.

The Company’s west Texas divisions are 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 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 division in northeast Texas and the City of Farmersville. 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. The PUCT 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 the PUCT. 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 has outsourced its materials warehousing function to an outside third party. The terms of the contract provide that the third party maintain an adequate level of inventory in order that the Company may meet its needs in a timely manner. The exclusive contract was for an initial term of 5 years, and has been extended and modified for another 5 years through November 2006. The terms of the contract also provide for

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termination at any time by either party with 90 days written notice. Upon any final contract termination by either party, the Company is required to purchase and pay for any inventory held by the third party at cost plus 10%. The estimated inventory value plus 10% is approximately $1,120,000 at December 31, 2003.

The Company has also outsourced its meter reading function. The basic terms of the three year contract provide for a fee per meter read, with the contract extended through 2005, unless either party gives 150 days written notice at any time.

At the time of the Company’s conversion from an electric cooperative to an investor owned electric utility, the Texas Public Utility Regulatory Act provided that a successor to an electric cooperative, such as the Company, would be treated as a cooperative for regulatory purposes. This would have allowed the Board of Directors of the Company to continue to set the rates that it charges its customers. In September 2001, the Company and the Cooperative filed an application to transfer the Cooperative’s Certificate of Convenience and Necessity to the Company. The CCN allows the Cooperative and the Company to serve electric customers in certain territories within the State of Texas. Various intervenors challenged this transfer and the Company’s right to treatment as a cooperative for regulatory purposes under the PURA. Following a contested proceeding, the Public Utility Commission of Texas approved the transfer of the CCN, effective September 1, 2003.

However, during the 2003 legislative session, Senate Bill 1280 (“SB 1280”) was adopted which amended the PURA so that the Company would be treated as an investor owned utility subject to regulation by the PUCT. The Company’s rates are now subject to regulation and approval by the PUCT, rather than the Company’s Board of Directors. In accordance with this change in the PURA, the Company filed its electric service tariffs with the PUCT on September 2, 2003. The PUCT is currently reviewing those tariffs. In addition, the PUCT initiated an inquiry to determine the reasonableness of the Company’s electric rates and required the Company to submit a standard rate filing package. The Company submitted that rate filing package in late February 2004. The filing contained a request for a rate increase for the Company’s various customer classes, aggregating approximately 14%. The increase is intended to cover increased costs of service related to, among other things, property taxes, computer and IT systems and costs associated with being a regulated investor owned utility. Several parties have intervened in these proceedings requesting, among other things, that the Company’s rates be decreased and that the Company be required to refund all monies it previously collected pursuant to a regulatory surcharge authorized by the Board of Directors during 2003. The Company believes its rates are reasonable and that the requested rate increase is appropriate based upon its cost of service and reasonable return on its invested assets.

The Company cannot determine what action the PUCT will take with respect to its current rates or its requested rate increase. The PUCT is required to rule on the rate request within a specified number of days. The Company expects a final ruling in the fourth quarter of 2004.

In 1999, legislature was adopted that provided for the restructuring of the electric utility industry in the State of Texas. The legislation provided 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 legislative purpose was to create a competitive retail market by allowing each retail electric customer to choose their provider of electricity and by encouraging competition. PURA treated municipally owned utilities and electric cooperatives differently from other utilities for retail competition. Investor owned electric utilities were required to allow retail competition in their service areas beginning January 1, 2002. Municipally owned utilities and electric cooperatives are able to choose whether or not to opt into retail competition. Retail competition deals only with the provision of electricity and not distribution or transmission services. Electric cooperatives were not required to functionally unbundle their operating and business activities as investor owned utilities were required to do. Since, prior to the passage of SB 1280, the Company was treated as a cooperative for regulatory purposes, it was not subject to these requirements. SB 1280 requires the PUCT to establish schedules and procedures for the Company to comply with the requirements of deregulation and

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competition, particularly the ability of retail electric customers to choose their energy supplier and the unbundling of its services. The PUCT has not yet established these procedures and schedules for the Company.

Although Management believes that House Bill 1642 concerning available customer choice shall occur no sooner than 2007 for the major service area in which the Company operates, the PUCT may issue an order to the Company for a required time frame that may be a later date, or a date sooner, than 2007.

As a regulated electric utility the Company’s rates are now subject to approval by the PUCT. This may affect the Company’s ability to fully recover its costs and its ability to earn a return on its assets which it believes is reasonable. Further, because of the time required to file and receive approval of rate changes, this could result in delays in the Company’s recovery of costs. Therefore, to recover costs in excess of the costs included in retail rates, the Company would have to make a rate filing with the PUCT, which could be denied in whole or in part. Any increase in costs over the costs recovered through rates would reduce our earnings if not offset by sales or other cost reductions. Purchased power costs are passed directly through to customers which reduces the Company’s exposure to variations in its costs of power. Regulation will also increase the cost of doing business in order to comply with the PUCT’s rules and regulations and to comply with the PUCT’s rate making practices. We cannot predict the impact these new regulatory requirements will have on the Company, or the costs of compliance.

In October 1999, the Company entered into an agreement with Lamar Electric Cooperative Association (“Lamar”), pursuant to which Lamar was to combine with, and become an operating division of, the Company. The members of Lamar subsequently approved this Combination Agreement. The agreement provided that if the combination was terminated by Lamar, with certain 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 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, 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 Services Agreement in November 2002. Lamar filed suit against the Company in the 62^nd District Court in Lamar County, Texas, seeking a declaratory judgment that it had a right to terminate both agreements without regard to payment of any kind to the Company. 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 is seeking reimbursement of all costs and expenses incurred with regard to the attempted combination which amount to at least $1.4 million and the cancellation fee of $300,000.

NewCorp’s predecessor, NewCorp Resources, Inc. (“NCR”) was a Texas corporation. In late 1996, NewCorp was formed and it was the sole shareholder of NCR. At that time, NCR owned the 305 mile transmissions system that serves the Company’s West Texas divisions and it held the CCN for that transmission system. NCR was dissolved in December 1996 and all of its assets, including the CCN, passed to NewCorp by operation of law.

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Accordingly, no proceeding was implemented at the PUCT to transfer the CCN. As a part of the Company’s efforts to refinance the transmission system, NewCorp recently requested that the PUCT correct the name on the CCN to reflect NewCorp as the holder of the CCN. The PUCT staff has recommended, and the Administrative Law Judges ruled, that this matter be handled through a nonadministrative proceeding. The Company does not believe that a formal proceeding to transfer the CCN is necessary, however it does not intend to appeal the ruling. A protracted PUCT proceeding could delay the Company’s efforts to refinance the transmission system.

The Company has been notified by the IRS that it intends to examine the federal income tax return of the Cooperative for the year 2001. Because the Cooperative is a nontaxable entity, and the Company believes it filed a proper return, management believes that the outcome of the audit will not have a material effect on the Company’s financial position, results of operations or liquidity.

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.

24. INCOME TAXES

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 years ended December 31, 2003 and 2002 (in thousands):

	2003			2002
Income tax expense calculated at the statutory rate of 34%	$	4,521		$	3,125
Income from nontaxable entities	(978		)	(1,626		)
State tax expense	219			132
Increase in operating and capital loss carryovers	—			(2,680		)
Change in effective tax rate of operating loss carryovers	—			(295		)
Change in valuation allowance	(1,643		)	1,599
Other	(21		)	159
Tax expense	$	2,098		$	414

The following is an analysis of consolidated income tax expense for the years ended December 31, 2003 and 2002 (in thousands):

	2003		2002
Current	$	2,098	$	414
Deferred	—		—
Tax expense	$	2,098	$	414

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

	2003			2002
Net deferred tax assets (liabilities):

Accrued expenses	$	1,758		$	333
Allowance for doubtful accounts	28			18
Net operating loss carryforwards	7,057			7,057
Capital loss carryforwards	2,765			2,849
Total deferred tax assets	11,608			$	10,257

Deferred revenue	—			(521		)
Property and equipment	(3,362		)	(19		)
Other	(172		)	—
Total deferred tax liabilities	(3,534		)	(540		)

Valuation allowance	(8,074		)	(9,717		)
Net deferred tax asset (liability)	$	—		$	—

As of December 31, 2003, the Company has net operating loss carryforwards of approximately $19.1 million. The net operating loss carryforwards are scheduled to expire in 2008 through 2021. The Company has benefited approximately $5 million of net operating loss carryforwards because it believes it has tax planning strategies available to realize the benefit of its tax loss carryforwards. In addition to the net operating loss carryforwards, as of December 31, 2003, the Company has a capital loss carryforward of approximately $7.5 million, which is scheduled to expire in 2004.

Though the Company itself is not under examination by the Internal Revenue Service, the Company was recently notified by the IRS that certain federal income tax returns of its Predecessor, and of its Predecessor’s affiliates, are or will be examined by the IRS. Although this process has just begun, and it is too early to tell its ultimate outcome, the Company believes that the Predecessor and its affiliates have adequately provided for any foreseeable outcome. Therefore, the Company does not anticipate any material impact to its earnings and cash flow as a result of these matters.

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25. SEGMENT INFORMATION

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

Business segment information as of and for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, is as follows (in thousands):

	TOTAL
Operating revenues
December 31, 2003	$	82,852
December 31, 2002	74,637
December 31, 2001	53,122
Net income
December 31, 2003	11,198
December 31, 2002	8,776
December 31, 2001	4,430
Identifiable assets
December 31, 2003	202,989
December 31, 2002	211,294
December 31, 2001	214,459
Capital expenditures
December 31, 2003	5,209
December 31, 2002	1,517
December 31, 2001	4,333
Depreciation and amortization
December 31, 2003	10,772
December 31, 2002	9,253
December 31, 2001	8,328
Interest expense, net
December 31, 2003	6,979
December 31, 2002	7,103
December 31, 2001	8,004

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26. QUARTERLY FINANCIAL DATA (UNAUDITED)

The following table summarizes results for each of the four quarters in the years ended December 31, 2003 and 2002 (in thousands except per share data):

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

Period ended December 2002
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 2003
Total revenues	$	22,344	$	19,250	$	23,343	$	17,915
Operating income	5,180		4,628		6,747		3,314
Net income before income taxes	3,760		3,283		4,718		1,535
Income tax expense	699		678		80		641
Basic earnings per share	2.35		2.00		2.96		.57
Diluted earnings per share	2.25		1.92		2.86		.55

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

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