ITEM 1. BUSINESS
The Company
Cap Rock Energy Corporation, its subsidiaries and affiliates (the “Company”) are engaged in the distribution and transmission of electricity in various noncontiguous areas in the State of Texas. The Company serves approximately 33,500 meters in 28 counties in Texas. The Company had approximately $200 million of assets at December 31, 2004, and generated revenues of approximately $83 million in 2004. The Company is regulated primarily by the Public Utility Commission of Texas and the Federal Energy Regulatory Commission. The Company is an exempt holding company under the provisions of the Public Utility Holding Company Act of 1935, and is exempt from all provisions of that act, except the section relating to the acquisition of the securities of other utilities.
The Company’s predecessor, Cap Rock Electric Cooperative, Inc. (the “Cooperative” or the “Predecessor”), was incorporated as an electric cooperative in the State of Texas in 1939. In 1998, members of the Cooperative adopted a plan for changing the corporate structure from a member owned cooperative to a shareholder owned corporation, and the Company was formed. The transfer of the assets, liabilities and issuance of stock was completed by early 2002. Transfer of the Cooperative’s Certificate of Convenience and Necessity (“CCN”), which allows a company to provide electric utility services within a certified territory in Texas, to the Company was approved by the Public Utility Commission of Texas (“PUCT”) effective September 1, 2003.
During the 2003 Texas legislative session, Senate Bill 1280 (“SB 1280”) was adopted which effectively brought the Company under the jurisdiction of the PUCT. See “State and Federal Regulation - State Regulation.”
Electric Market
The electric industry is currently undergoing many changes, both in Texas and nationwide. Total revenues from sales of electricity to ultimate consumers in the United States total over $250 billion per year. While the Company is not currently subject to competition, it has operated in dually certified areas since its existence. Since the Company is regulated by the Public Utility Commission of Texas, it will be subject to competition in the future. See State and Federal Regulations - State Regulation.
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 market place gives the Company an advantage over other similar sized utilities. The Company expects that as competition becomes more intense and operations become more complicated, more utilities will want to divest themselves of customers in these sparsely populated areas. See also Business Strategy.
Business Strategy
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 significant potential for growth. This may include acquiring smaller utilities or pieces of larger utilities in these types of rural areas.
Distribution Operating Statistics
Revenues and Customers
The Company’s operating revenues come from electric or electric related sales. Annual sales for 2004 to the Company’s commercial/industrial, residential and irrigation customers accounted for approximately 54%, 38%, and 8%, 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 30% 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 8% of all electric sales for 2004, approximately 80% of those irrigation sales occurred during the period April 1 to September 30.
Nonutility Investments and Property
As of December 31, 2004, the Company’s only nonelectric business investment is an office building and the related land that serves as its general corporate headquarters in Midland, Texas.
The Company previously had a 42% interest in MAP Resources, Inc. (“MAP”) which it accounted for under 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, which was repaid in July 2004.
The Company had a 15% interest in United Fuel and Energy Company (“United Fuel”), which is engaged in the petroleum distribution business. 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 was a secondary guarantor on United Fuel’s note of $3,500,000, which United Fuel repaid in November 2004, and the Company was released from the guaranty.
In March 2004, the Company signed an agreement with a shareholder of United Fuel to sell the Company’s shares of stock in United Fuel for $1,300,000 in exchange for a note receivable from that shareholder. See Notes 7 and 16 to the consolidated financial statements.
The Company had limited partner interests in real estate partnerships that it sold in February 2004, to an unrelated third party in exchange for a note receivable. See Notes 7 and 9 to the consolidated financial statements.
Employees
As of December 31, 2004, the Company had 111 full-time and six part-time employees, none of which were members of any labor unions.
State and Federal Regulation
State Regulation
As a Texas electric utility, the Company is subject to the jurisdiction of the Public Utility Commission of Texas, which has general regulatory authority over rates, 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, 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. A hearing will be held in April, 2005 to determine if the tariffs filed by the Company are the tariffs that were approved by the Company’s Board of Directors, which was the Company’s previous regulatory authority. The Company believes the issue is moot because any current tariff will be superseded by the tariff that is ultimately approved by the PUCT in the current rate case. In addition, the PUCT initiated an inquiry to determine the reasonableness of the Company’s electric rates and required the Company to submit a rate filing package.
The Company submitted that rate filing package in late February 2004. A hearing on the Company’s filing, which included a request for a rate increase, was held in October 2004. On March 17, 2005, the Administrative Law Judges (“ALJ’s”) issued a Proposal for Decision (“PFD”). The PFD recommended a 7.49% rate decrease for Cap Rock. This amounts to an annual revenue decrease of approximately five million dollars. Several intervenors had sought rate decreases which were much larger than the recommendation of the ALJ’s. A final ruling, which can be appealed by Cap Rock or any of the intervenors, is expected by June 2005.
The Company feels that its rates and its requested rate increase are justified and that the evidence supports that. The Company will request that the PUCT reject the recommendation of the ALJ’s and grant its requested rate increase. The Company has received recommendations from Administrative Law Judges in the past which were not in its favor, only to prevail when the issues were considered by the PUCT. 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 rate base. However, the Company cannot determine what action the PUCT will take with respect to the PFD. Notes 19 and 22 to the consolidated financial statements.
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 interstate transmission of electric power, maintenance of accounting records in accordance with the uniform system of accounts and the issuance of certain securities. See also Note 22, “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. During 2002, the Company applied for, and FERC approved, the unbundling of transmission rates relating to its west Texas transmission system. Our 305 mile transmission system that serves the west Texas division is currently in the SPP. The Company is therefore under the jurisdiction of the SPP through Southwestern Public Service Company, its wholesale power provider for west Texas. Management believes that FERC Order No. 2000 and continued participation in the SPP will not have a material effect on its operations.
Competition and Restructuring in the Utility Industry
For many years the Company and its predecessor have faced competition in providing electric distribution services. A large percentage of its service territory is dually certified with other utilities, therefore even though the Company is not currently subject to competition pursuant to the legislation that was passed in Texas in 1999, it competes with other utilities in much of its service territory. Many of the Company’s competitors, like TXU Energy and its affiliate, TXU-Electric Delivery, are much larger than the Company and have financial resources that are much greater than the Company’s. TXU-Electric Delivery, 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. The Company’s retail rates are comparable to those of TXU-Electric Delivery and other retail electric providers.
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, not just those certified to serve in the service territory. However, the Company will continue to provide distribution services and receive a wires charge.
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. See Note 19 to the consolidated financial statements.
Power Requirements
The Company purchases power for resale to its retail customers from wholesale suppliers and distributes that power to its customers through approximately 305 miles of transmission lines and approximately 11,000 miles of distribution lines. The Company’s transmission systems interconnect with the systems of power suppliers and other utilities, to permit bulk power transactions with other electricity suppliers. The Company, owns and operates the transmission system that supplies wholesale power to the Company’s west Texas divisions, which is a part of the Southwest Power Pool. SPP coordinates transmission services among its members. In 2004, 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%, 13% and 13%, 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, and was extended until 2005; the Company has completed the process of requesting proposals for power providers and expects to have a contract signed within the next few months. Because the market price of gas has increased, Management expects the price to be higher. 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.
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 2005 will consist primarily of costs to maintain the Company’s distribution and transmission systems. Total gross property additions, including construction work in progress, for the years ended December 31, 2004, 2003 and 2002, were $3,228,000, $5,209,000 and $1,517,000, respectively. Management’s planned capital expenditures for the next 12 months are $7,916,000.
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 electronically filing with, or furnishing to, the Securities and Exchange Commission. The information contained on the website is not part of this document.
ITEM 2.
ITEM 2. PROPERTIES
Utility Plant
The Company owns and operates a transmission system and distribution systems. The transmission system carries high voltage electricity over longer distances. Substations step the voltage down and distribution lines carry that power to the ultimate customers. The Company’s 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. 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 Company has two other noncontiguous distribution systems with nine. The Company also owns real estate related to its electric distribution and transmission business, including easements, right-of-ways, and land where substations, as well as distribution and transmission poles and lines, are located. Real estate and division office locations in Stanton, Colorado City, Brady and Celeste, Texas, are also owned. The distribution system is pledged as security under the Company’s mortgage notes.
Nonutility Property
The Company owns a 45,000 square foot office building and the related land that is used as its general corporate headquarters in Midland, Texas. The Company occupies approximately 35% of the building and the remainder is leased to commercial tenants.
In February 2004, the Company sold its limited partner interests in real estate partnerships for $286,000 in exchange for a note receivable, which resulted in no gain or loss. 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 interests also involved the transfer of those guarantees to the buyer. See Notes 7 and 9 to the consolidated financial statements.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims, except for the proceedings described in Note 22 to the consolidated financial statements, will not have a material impact on the Company’s financial position, operating results or liquidity.
See Note 22, “Commitments and Contingencies,” to the consolidated financial statements for a discussion of legal proceedings which may be material to the Company’s operations and financial condition.
ITEM 4.
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 2004.
Executive Officers of the Registrant
The executive officers of the Company are as follows:
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.
William L. West became President of the Company in December 2004 and was appointed to serve on the Board of Directors at the same time. He served as a consultant to the Company from July through December 2003 and joined the Company full time in January 2004 as Chief Strategic Officer, and was appointed Vice-President in July 2004. Prior to this he was a Senior Manager with KPMG, LLC serving in client service and strategic corporate tax consulting capacities from 1997 through July 2003. Mr. West is a certified public accountant.
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 B. Page 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. Page is a certified public accountant.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Market Information and Holders of Common Stock
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.
As of March 21, 2005, there were approximately 12,148 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 payment of dividends.
Equity Compensation Plans
The following table sets forth certain information regarding the Company’s equity compensation plans as of December 31, 2004:
ITEM 6.
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, 2004, 2003 and 2002, nine months ended December 31, 2001 and 2000, and the year ended March 31, 2001. 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.”
(1) The Company changed its year-end from March 31 to December 31, effective December 31, 2001.
(2) Includes $1,357,000 of impaired costs related to the Lamar Combination for the year ended December 31, 2002. See Note 4 to the consolidated financial statements.
(3) Upon conversion to a shareholder owned corporation, the activities and transactions of the parent became taxable.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Cautionary Statement Regarding Forward-Looking Statements
Certain written and oral statements made by our Company or with the approval of an authorized executive officer of our Company may constitute “forward-looking statements” as defined under the Private Securities Litigation Reform Act of 1995, including statements set forth in this Form 10-K as they relate to Management’s future plans and objectives, and in other filings with the Securities and Exchange Commission. Generally the words “may,” “will,” “expect,” ‘intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof and similar terminology identify forward-looking statements, which generally are not historical in nature.
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, growth, sales projected costs and plans and objectives of Management for future operations, are forward-looking statements. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from our Company’s historical experience and our present expectations or projections. As and when made, management believes that these forward-looking statements are reasonable. However, caution should be taken not to place undue reliance on any such forward-looking statements since such statements speak only as of the date when made. 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. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
The following are some of the factors that could cause our Company’s actual results to differ materially from the Company expectations described in or underlying our Company’s forward-looking statements:
• Weather conditions could affect our electricity sales and revenues;
• Change in rate structure and ability to earn a fair return on our rate base and recover the costs of operations could affect our operations. A negative outcome in our current rate proceeding could affect our Company’s profits;
• 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 could affect revenues and earnings and could cause us to lose customers through 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 could cause our purchased power cost to increase, which could in turn affect our customers’ useage and our revenues;
• 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, 2004, 2003, and 2002 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 noncontiguous areas in the State of Texas. The Company provides service to over 33,500 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, 6,200 meters in the central Texas area around Brady, and over 4,300 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 305 miles and then over 11,000 miles of distribution lines. The Company’s primary focus is on the distribution of electricity to its customers, and therefore has not and does not plan to engage in the generation of electricity. 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 filed its tariff for electric service with the PUCT. The Company was also required to submit a standard rate filing package to the PUCT in late February 2004, in connection an inquiry instituted by the PUCT to determine the reasonableness of the Company’s electric rates. This filing contained a request for a rate increase for some customer classes. A hearing was held in October 2004 regarding the Company’s rate filing package and a final decision is expected in the second quarter of 2005. A hearing will be held in April 2005, to determine if the tariffs filed by the Company are the actual tariffs that were approved by the Company’s Board of Directors, which was the Company’s previous regulatory authority. The Company believes the issue is moot because any current tariff will be superseded by the tariff that is ultimately approved by the PUCT in the current rate case. A total of $3,593,000 in third party costs were incurred to prepare the rate filing package, as well as the public hearing process. The amount and period over which the Company will be allowed to recover these costs will be determined by the PUCT.
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 was a secondary guarantor for United Fuel’s note, and was required to record a guarantee obligation based on fair value. When United Fuel repaid the note to the bank in November 2004, the Company’s obligation as guarantor was effectively released and it was able to eliminate the recorded $35,000 guarantor obligation.
In March 2004, the Company signed an agreement with a shareholder of United Fuel to sell the Company’s shares of stock in United Fuel at a sales price of $1,300,000, in exchange for a note receivable from that shareholder. The terms of the agreement provide for repayment after United Fuel has completed certain capitalization arrangements. All conditions required pursuant to the agreement have been satisfied, and the Company expects payment as scheduled in 2005. Recognition of the gain of $940,000 has been deferred until principal payments have been received.
The financing arrangements with Beal Bank provided for an initial and an additional advance. The Company drew the initial advance in September 2003. A collateralized cash investment was used to repay the initial advance of $14,169,000 in November 2004.
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.
Rate Regulation. 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 immediately against income 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 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 or 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 accordingly by either receipt from, or refund to, the customer of the net deferred amount.
Derivative Instruments and Hedging Activities. The Company may enter 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. Derivative transactions minimize the fluctuations in the Company’s customers’ power bills. These 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, 2004 and 2003, no derivative positions were 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.”
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, 2004 and 2003, the Company has recorded $3,285,000 and $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. The ultimate amount of deferred tax assets realized could be materially different from that recorded, as impacted by changes in federal income tax laws to enable us to realize the related tax assets.
At December 31, 2004 and 2003, there were approximately $25,630,000 and $20,800,000 of net operating loss carryforwards that expire in 2009 through 2024, and may be used to offset future taxable income. The Company recorded valuation allowances against the deferred tax assets related to net operating losses. This determination was based on the 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
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 had been experiencing a severe long-term drought, but these conditions are much less severe than in the past.
Although electric revenues decreased only $253,000 between 2003 and 2004, the aggregate components were:
• An increase in power cost recovery of $2,702,000;
• Increase in wholesale sales and kWh sales of $801,000;
• A decrease in 2004 of $3,755,000 as a result of the 2003 change in accounting principle.
The increase in power cost recovery is comprised of the increase of the pass through of fuel costs to customers of $4,150,000, and a decrease in the amount of revenue recognition related to a regulatory surcharge authorized by the Board of Directors of $1,448,000. It was intended to recover some of the expense incurred in connection with the Company’s response to Opposing Intervenors actions in the CCN case. A total of $2,354,000 was billed to customers from June 2003 through February 2004; $92,000 was recognized as revenue in 2004, $1,539,000 was recognized as revenue in 2003, and the remainder of $723,000 is shown as a regulatory liability on the balance sheet at December 31, 2004.
Electric revenues increased $8,067,000 for 2003 as compared to 2002. This rise is due to multiple factors:
• An increase of $4,600,000 for recovery of power costs;
• An increase in revenue accruals of $3,400,000 due to the effect of the change in accounting principle in 2003.
The Company had been realizing deferred revenue of $4,364,000 equally over a 24 month period from January 2002 to December 2003. This revenue was recognized equally in both the 2003 and 2002 periods, and was billed through the power cost recovery factor, and is not being reflected in any future periods. This item related to purchased power that was expensed in prior years.
Because of a change in the Public Utility Regulatory Act (“PURA”), as of September 1, 2003, the Company’s rates became subject to regulation and approval by the PUCT, not the Company’s Board of Directors. In accordance with this change in the PURA, the Company filed its tariffs for electric service on September 2, 2003. The staff of the PUCT reviewed those tariffs and provided comments and proposed changes to bring the tariffs into compliance with PUCT rules and regulations. Because the tariffs, when adopted, were not subject to PUCT regulation, some of the provisions did not comply with PUCT rules and regulations since that was not a requirement when the tariffs were adopted. Now that the Company is subject to PUCT regulation, the Company made proposed amendments to its tariff as suggested by the PUCT staff. The PUCT staff reviewed the proposed changes and recommended that the tariff be approved. Prior to the Administrative Law Judge entering a ruling approving the tariff, with the proposed changes, several of the group of intervenors in the case were successful in obtaining a legislative request that the matter be referred to the State Office of Administrative Hearings (“SOAH”)
for a hearing on the merits. As a result, the matter was referred to SOAH and a hearing is currently scheduled for April, 2005. The hearing will be limited to whether the tariffs filed by the Company are the actual tariffs that were properly approved by the Company’s Board of Directors, which was the Company’s previous regulatory authority. The Company believes the issue is moot because any current tariff will be superseded by the tariff that is ultimately approved by the PUCT in the current rate case.
In October 2004, the PUCT initiated an inquiry to determine the reasonableness of the Company’s rates and ordered the Company to submit a rate filing package. The Company prepared and filed a rate filing package that contained a request for a rate increase for some customer classes. The Company initially requested a $6,333,000 overall annual after tax increase but due to adjustments made while preparing for the hearing on the merits in the case, that amount was adjusted downward to $5,021,000. Hearings were held before the State Office of Administrative Hearings from October 5, 2004, through October 14, 2004. During such hearings, the Company presented testimony and evidence in support of its requested rate increase. Numerous intervening parties and the PUCT staff presented evidence and testimony in opposition to the rate increase and in support of a rate decrease. The parties have filed briefs in support of their positions. The Company has agreed to extend the effective date for the requested rate increase until June 17, 2005. A hearing was held in December 2004, to determine the amount of rate case costs that the PUCT will allow the Company to recover from its customers, as well as the period of recovery. The Company believes all its rate case costs are reasonable and necessary and should be recoverable. Any amount not allowed for recovery will be expensed immediately. As of December 31, 2004, $3,593,000 of third party costs had been incurred in connection with the rate case, and are shown on the balance sheet as a regulatory asset. These costs were deferred pending approval of recovery by the PUCT. See also Note 11 to the consolidated financial statements.
On March 17, 2005, the Administrative Law Judges (“ALJ’s”) issued a Proposal for Decision (“PFD”). The PFD recommended a 7.49% rate decrease for Cap Rock. This amounts to an annual revenue decrease of approximately five million dollars. Several intervenors had sought rate decreases which were much larger than the recommendation of the ALJ’s. A final ruling, which can be appealed by Cap Rock or any of the intervenors, is expected by June 2005.
The Company feels that its rates and its requested rate increase are justified and that the evidence supports that. The Company will request that the PUCT reject the recommendation of the ALJ’s and grant its requested rate increase. The Company has received recommendations from Administrative Law Judges in the past which were not in its favor, only to prevail when the issues were considered by the PUCT. 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 rate base. However, the Company cannot determine what action the PUCT will take with respect to the PFD.
If the Company’s request for a rate increase is approved by the PUCT, the Company may suffer a decline in its customer base. Because the outcome of the rate request or rate order is unknown, the Company is unable to predict the effect of such order.
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 increased $3,454,000 from 2003 to 2004. The net changes related to:
• Increase in fuel cost related to the regulatory liability due to overcollection of power cost recovery of $3,074,000;
• Increase in power costs of $4,754,000;
• Decrease of $4,412,000 in 2004 because of the conclusion in 2003 of the rate making treatment of the capital lease payments associated with the transmission system.
Purchased power only increased by $145,000 from 2002 to 2003. The net change is attributable to:
• An increase in power costs of $2,966,000 which includes $1,318,000 of power cost lag because of the change to the accrual method of accounting;
• 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 2004, which increased the cost of purchased power and is passed directly through to customers.
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. Because the lease was extinguished in September 2003, the treatment is no longer applicable, and the remaining net book value of the transmission system is being depreciated over its remaining life, and that expense is 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 $196,000 and $2,808,000, respectively, between 2004 and 2003, and 2003 and 2002. 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.
General and administrative expenses increased by $2,879,000 from 2003 to 2004, because of the following:
• Increased costs in 2004 of $1,610,000 related to IT support and outsourced IT functions;
• Increased expenditures of $218,000 associated with public relations;
• Decreased overhead allocation from 2003 to 2004 to utility plant and operations and maintenance of $890,000 resulted in higher costs remaining in general and administrative.
General and administrative expenses decreased by $2,505,000 between 2002 and 2003, because of 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 Company expects regular 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 resources and personnel.
In December 2002, the shareholders approved the Stock Incentive Plan which authorized a total of 800,000 shares under that plan. See “Equity Compensation Plans” under Item 5. 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. Both awards
are being amortized to expense over periods of 2 to 5 years, with the expense reflecting the fair value of the award.
In December 2004, an additional award of stock was granted to employees, officers and directors. Employee awards vest over two years, and officers’ and directors’ awards vested immediately. The fair value of this award is being amortized to expense over the applicable vesting period. Expected noncash compensation expense by year for all awards is as follows: 2005 - $1,225,000, 2006 - $324,000, 2007 - $316,000 and 2008 - $108,000.
Depreciation and amortization increased $662,000 from 2003 to 2004 because of the following factors:
• Conclusion in 2003 of the rate making treatment of the amortization of property and equipment associated with the transmission system capital lease caused an increase of $412,000 because the treatment is no longer applicable;
• Amortization in 2004 of $367,000 relative to the capitalized costs of the IT system.
Depreciation and amortization increased $920,000 from the year ended 2002 as compared to 2003 for various reasons:
• Increased depreciation expense of $359,000 associated with changes in estimated useful lives of certain general plant assets;
• 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 and automate certain processes, management recognized the need for a more sophisticated and responsive IT system and associated applications. The Company engaged an 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 related to compliance with Section 404 of the Sarbanes Oxley Act of 2002.
Certain IT costs associated with the change in the operating environment, the software applications and implementation process have been capitalized. These costs aggregated $4,486,000 and $3,881,000 at December 31, 2004 and 2003, and the Company began a 5 year amortization period beginning March 2004, which was the end of the planned implementation. In addition, the ongoing costs for maintenance and IT support are based on the number of meters per respective month and, based on the number of meters as of December 31, 2004, 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 mid 2005.
Historically, property tax expense had remained relatively constant. In 2004, such expenses increased $580,000 because of current appraisal methodologies used in the ad valorem taxation of investor owned utilities in Texas, as well as the Company’s revenue-generating ability, as compared to its former status as a cooperative.
Interest expense decreased $29,000 between 2003 and 2004 because of the following:
• Amortization of all remaining fees and costs incurred with respect to the Beal Bank loan caused an increase of $787,000;
• The initial Beal Bank advance was drawn on in September 2003 and repaid in November 2004, with a resulting net increase of $795,000;
• The cross-collateralized note payable to a bank was extinguished in September 2003 causing a decrease of $566,000 between the periods;
• Interest expense on mortgage debt reflects a decrease of $126,000 because of the declining balance on the debt.
• In 2004, there was no amortization of the fees and costs associated with the original transmission system capital lease because the lease was extinguished in September 2003. This caused a decrease of $984,000.
Interest expense increased $609,000 between 2002 and 2003 because of the following:
• Increase of $478,000 because of the draw on the initial advance from Beal Bank in September 2003 at a rate of 10.75% per annum;
• Initial amortization of $333,000 of the legal fees and costs in 2004 incurred with respect to consummation of the Beal Bank loan;
• Amortization of the fees and costs associated with the original transmission system capital lease were accelerated by $544,000, in order that these costs would be fully amortized by the end of the lease term;
• Decrease in interest on mortgage debt of $535,000 because the Company was able to lock in lower interest rates, coupled with a declining principal balance;
• Decrease of $186,000 in interest associated with the cross-collateralized note payable to a bank because of its declining balance and it was extinguished in September 2003.
As described more fully in Note 22 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.
Because the investment in MAP was sold in 2003, the 2004 period will not reflect any transactions related to MAP.
When the Company and the Shareholders’ Trust entered into a Voting Agreement in December 2004, the Company recorded a long term liability based on fair value of $129,000 and a corresponding expense. This
was for consideration whereby the shares held by the Trust will be voted by the Trustees as directed by the Company for as long as the shares are held in the Trust. See Note 21 to the consolidated financial statements.
Income tax expense decreased $4,277,000 between 2003 and 2004, and increased $1,723,000 between 2003 and 2002. As of December 31, 2004, the Company has net operating carryforwards of approximately $25.6 million which are scheduled to expire in 2009 through 2024. The Company has a valuation allowance of $3,285,000 against the net deferred tax asset. This valuation allowance decreased $4,789,000 from 2003 to 2004 in part because of a change in temporary differences and the resulting net deferred taxes, and the changes in net operating losses between the two years.
In early 2004, the IRS notified the Company that it intended to examine the federal income tax return of the Cooperative for the year 2001. The Company and the IRS are in the final stages of that process, and Management believes there will be no impact on the Company’s financial position or results of operations.
Contractual Obligations and Other Commitments
The following table summarizes the Company’s obligations and commitments to make future payments under certain contractual obligations:
(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 and certain professional services.
(2) Includes actuarially calculated amounts for post retirement healthcare costs of $849,000, $838,000, $855,000, $827,000, and $776,000 for the years ended 2005, 2006, 2007, 2008 and 2009, respectively, as well as $33,926,000 for the years 2010 through 2050.
(3) The Company has a contract with the City of Farmersville, Texas, to act as an agent to provide power, assume related billing and collections functions and is obligated to the City to make payments on a revenue sharing type basis. The 2005, and estimated 2006, annual payments aggregate $621,000.
(4) Payments to or benefits to be provided to advisory directors are included.
Liquidity and Capital Resources
As of December 31, 2004, the Company had:
• Cash and cash equivalents of $20,968,000;
• Working capital of $9,160,000; and
• Long-term indebtedness of $134,032,000, 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.
Included in the $9,160,000 of working capital above, the Company has a $3.4 million income tax receivable. $1.9 million of this receivable represents current year income tax overpayments, and $1.4 million represents income taxes to be recovered through the carry back to prior years of the Company’s current year net operating loss. The Company should receive the $3.4 million federal income tax receivable during 2005.
Through 2001, one of the Company’s primary sources of capital and liquidity had been borrowings from the Company’s primary lender, National Rural Utilities Cooperative Finance Corporation (“CFC”). 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 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 a stated percentage. At December 31, 2004, the Company was in compliance with its CFC loan agreements and the applicable covenants. See note 11 to the consolidated financial statements for a discussion of CFC’s waivers related to the prior conversion from a cooperative to a stock holder owned corporation.
Substantially all of the CFC mortgage notes are subject to interest rate repricing at the end of various periods, at the Company’s option. The Company anticipates refinancing one of the mortgage notes that has a balloon payment of $26,367,000 due in 2007. Mortgage notes with CFC as of December 31, 2004, and the applicable interest rates are as follows:
FERC approval was received in August 2003 for NewCorp to borrow $31,500,000 from Beal Bank S.S.B. (“Beal Bank”). The initial advance of $14,169,000 was used for payment of the balloon payment on the transmission system capital lease in September 2003. Simultaneously, the sinking fund of $8,207,000 was released by the lessee, and used to partially fund a restricted securities account of $14,169,000, which was the only asset collateralized by Beal Bank.
Interest on the Beal Bank loan was 10.75%, payable monthly. The financing arrangement provided for a commitment fee, which totaled $457,000 for the initial advance. Additional amounts paid to Beal Bank were reimbursement of expenses, attorney fees, appraisals and consulting, which at December 31, 2004, aggregated $1,184,000. Prepayment of the initial advance was not allowed unless the additional advance was funded before the September 9, 2004, original due date. Two amendments to the financing agreement extended the due date of the initial advance, and the collateralized securities account was then used to repay the initial advance in November 2004. In the accompanying consolidated balance sheet at December 31, 2003, the initial advance of $14,169,000 is shown in current liabilities because it was not certain that the Company would draw on the additional advance from Beal Bank.
Stock awards were made to employees, officers and directors in both 2004 and 2003. Noncash compensation expense of $4,925,000 and $2,135,000 was recorded for 2004 and 2003, because the fair value of the award is
being amortized over each of the applicable vesting periods. Expected noncash compensation expense by year is as follows: 2005 - $1,225,000, 2006 - $324,000, 2007 - $316,000 and 2008 - $108,000.
The terms of the note receivable agreement with the shareholder of United Fuel provide for repayment after United Fuel has completed certain capitalization arrangements. All conditions required pursuant to the agreement have been satisfied, and the Company expects full payment of the $1,300,000 in 2005.
When the Company and the Cap Rock Energy Shareholders’ Trust entered into a Voting Agreement in December 2004, the Company recorded a long term liability based on fair value of $129,000 and a corresponding expense. This was for consideration whereby the shares held by the Trust will be voted by the Trustees but as directed by the Company for as long as the shares are held in the Trust. This liability will be paid out as the owners of the shares are located and the shares are issued to the owner or their heirs. Therefore, this liability will be paid over future years, and is not expected to require a material amount of cash in any one year. See Note 21 to the consolidated financial statements.
The Company provides continued major medical coverage to retired employees and their dependents. The actuarially calculated estimates of costs for future years is shown in the table under “Contractual Obligations and Other Commitments.” A one percentage point change in assumed health care cost trend rates would have the following effects:
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 2005, including those enumerated in the table under “Contractual Obligations and Other Commitments.”
New Accounting Standards
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R revises SFAS No. 123, “Accounting for Stock-Based Compensation.” This new standard generally requires the cost associated with employee services received in exchange for an award of equity instruments be measured based on the grant-date fair value of the award and recognized in the financial statements over the period during which the employee is required to provide services in exchange for the award. SFAS No. 123R also provides guidance on how to determine the grant-date fair value for awards of equity instruments, as well as alternative methods of adopting its requirements. SFAS No. 123R is effective as of the beginning of the first interim or annual reporting period after June 15, 2005, and applies to all outstanding and unvested share-based payment awards at a company’s adoption date. 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, effective January 1, 2003. Therefore, SFAS No. 123R is not expected to have an impact on the Company’s consolidated financial statements.
In May 2004, the Financial Accounting Standards Board issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). FSP 106-2 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act and requires certain disclosures pending determination as to whether the sponsor’s postretirement health care plan reasonably expect to qualify for beneficial treatment under the Act. The Company qualifies for the subsidy, which approximates $34,000 for the year ended December 31, 2004. See Footnote 15.
ITEM 7A.
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, 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 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 sold its limited partner interests 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. The sale of the partnership interests involved the transfer to the buyer of guarantees of debt.
The Company sold its investment in United Fuel and Energy Corporation in exchange for a note receivable of $1,300,000, which is collateralized by the original stock. The terms of the agreement provide for repayment after United Fuel has completed certain capitalization arrangements. All conditions required pursuant to the agreement have been satisfied, and the Company expects payment as scheduled in 2005.
Interest Rate Risk
The Company is 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 $6,467,000 with current interest rates of 4.85% are due to be repriced in January 2006, mortgage notes of $64,055,000 with current interest rates of 5.15% are due to be repriced in January 2007, $33,017,000 with current interest rates of 4.7% are due to be repriced in January 2006, $5,960,000 with current interest rates of 4.5% are due to be repriced in January 2007. No repricing is scheduled for the following: $27,872,000 with a fixed rate of 4.3%, $3,590,000 with a fixed rate of 4.2%, $2,000 with a fixed rate of 7%, and $2,791,000 are variable rate notes. A 1% change in interest rates would cause a change of $1,438,000 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 provided 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 ten months of 2004 that the investments were held was less than one percent.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements are set forth on pages through of this Form 10-K.
ITEM 9.
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.
ITEM 9(b).
OTHER INFORMATION
None
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directors And Executive Officers
The information relating to the Company’s directors required by Item 10 is set forth in the definitive proxy statement to be filed with the SEC for the 2005 Annual Meeting of Shareholders to be held on June 14, 2005. 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.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 will be set forth in the definitive proxy statement to be filed with the SEC for the 2005 Annual Meeting of Shareholders to be held on June 14, 2005. 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 will be set forth in the definitive proxy statement to be filed with the SEC for the 2005 Annual Meeting of Shareholders to be held on June 14, 2005. 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 will be set forth in the definitive proxy statement to be filed with the SEC for the 2005 Annual Meeting of Shareholders to be held on June 14, 2005. 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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information called for by Part III, Item 14, is included in the proxy statement relating to our annual meeting of shareholders to be held on June 14, 2005, and is incorporated herein by reference.
PART IV
ITEM 15.
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.
Financial Statement Schedule
The following financial statement schedule is included in Item 14: Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2004, 2003 and 2002.
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 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
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) (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/03) (1)
Exhibit 10.23a
Employment Contract between Cap Rock Energy Corporation and Ulen A. North, Jr. dated September 12, 2001 (originally filed with Amendment No. 2 to Form S-1 dated 4/25/01) (1)
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 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
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 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
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 (originally filed with Form 10-K for year ended 12/31/02 dated 4/10/03) (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, 1992 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/03) (1)
Exhibit 10.82
Managed Services Agreement with Delinea Corporation dated March 12, 2003 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/03) (1)
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. (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
Exhibit 10.84
Stock Acquisition Agreement between NewCorp Resources Electric Cooperative, Inc. and United Fuel and Energy Corporation dated March 18, 2004 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
Exhibit 10.85
Employment Contract between Cap Rock Energy Corporation and William West dated December 30, 2003 (originally filed with Form 10-Q for period ended 06/30/04 dated 08/1904) (1)
Exhibit 10.86
Amended Letter between Beal Bank S.S.B. and New Corp Resources dated September 9, 2004 (originally filed with Form 8-K dated 0/28/04) (1)
Exhibit 10.87
Second Amended Letter between Beal Bank S.S.B. and New Corp Resources dated September 24, 2004 (originally filed with Form 8-K dated 10/01/04) (1)
Exhibit 10.88
Amended Shareholders’ Trust between Cap Rock Energy Corporation Shareholders’ Trust and Alfred J. Schwartz and Robert G. Holman dated December 31, 2004 (originally filed with Form 8-K dated 1/06/05) (1)
Exhibit 10.89
Right of First Refusal Agreement between Cap Rock Energy Corporation Shareholders’ Trust and Alfred J. Schwartz and Robert G. Holman dated December 31, 2004 (originally filed with Form 8-K dated 1/06/05) (1)
Exhibit 10.90
Voting Agreement between Cap Rock Energy Corporation Shareholders’ Trust and Alfred J. Schwartz and Robert G. Holman dated December 31, 2004 (originally filed with Form 8-K dated 1/06/05) (1)
Exhibit 10.91
Proposal For Decision, PUC Docket No. 28813, issued March 17, 2005 (originally filed with Form 8-K dated 3/17/05)(1)
Exhibit 14.1
Cap Rock Energy Corporation Code of Ethics dated December 2, 2003 (originally filed with Form 10-K for year ended 12/31/03 dated 4/10/04) (1)
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 25, 2005.
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
Director, Co-Chairman of the Board,
Chief Executive Officer
March 25, 2005
David W. Pruitt
/s/ WILLIAM L. WEST
Director, President
March 25, 2005
William L. West
/s/ RUSSELL E. JONES
Director, Co-Chairman of the Board
March 25, 2005
Russell E. Jones
/s/ S. D. BUCHANAN
Director
March 25, 2005
S. D. Buchanan
/s/ FLOYD L. RITCHEY
Director
March 25, 2005
Floyd L. Ritchey
/s/ MICHAEL D. SCHAFFNER
Director
March 25, 2005
Michael D. Schaffner
CAP ROCK ENERGY CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
ALLOWANCE FOR DOUBTFUL ACCOUNTS
(AMOUNTS STATED IN THOUSANDS)
Report of Independent Registered Public Accounting Firm, KPMG LLP
Consolidated Statements of Operations
Years ended December 31, 2004, 2003 and 2002
Consolidated Balance Sheets
December 31, 2004 and
Consolidated Statements of Equity
Years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows
Years ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Cap Rock Energy Corporation:
We have audited the accompanying consolidated balance sheets of Cap Rock Energy Corporation and subsidiaries (the Company) as of December 31, 2004 and 2003, and the related consolidated statements of operations, statement of equity, and cash flows for each of the years in the three-year period ended December 31, 2004. In connection with our audits of the consolidated financial statements, we also have audited financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Cap Rock Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U. S. generally accepted account principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
KPMG LLP
Midland, Texas
March 25, 2005
CAP ROCK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
CAP ROCK ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
CAP ROCK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
CAP ROCK ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
CAP ROCK ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2004, 2003 AND 2002
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
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, commercial and irrigation, 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. Through its subsidiaries, the Company 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 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 balances 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
In conformity with accounting principles generally accepted in the United States, the preparation of the Company’s consolidated financial statements 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 values 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
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. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the rate making process.
The significant regulatory assets and liabilities are as follows:
The Company will be allowed to recover certain rate case costs over a period mandated by the PUCT. Any costs not allowed for recovery will be expensed immediately. A decision from the PUCT concerning the amount and period of recovery is expected in June 2005.
Both regulatory liabilities are expected to be refunded to customers within 12 months.
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.
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
At December 31, 2003, the Company was required to maintain a restricted cash investment of $14,169,000 which served as collateral for the initial advance from Beal Bank S.S.B. Terms of the loan agreement provided for investment of the cash collateral only in certain specified types of investments. Interest earned was not restricted, and was not classified as restricted. The initial advance was repaid in November 2004, with funds from the collateralized restricted cash investment used to satisfy the debt payment. See Note 12.
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, 2004 and 2003, the allowance for doubtful accounts was $115,000 and $78,000, respectively. Bad debt expense for the years ended December 31, 2004, 2003 and 2002, was $143,000, $113,000 and $120,000, respectively.
Inventories
Although the Company utilizes an independent third party for its materials warehousing function, 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.
An investment is considered impaired if the fair value of the investment is less than its cost. Generally, an impairment is considered other-than-temporary unless (i) the Company has the ability and intent to hold an investment for a reasonable period of time sufficient for an anticipated recovery of fair value up to (or beyond) the cost of the investment; and (ii) evidence indicating that the cost of the investment is recoverable within a reasonable period of time outweighs evidence to the contrary. If impairment is determined to be other-than-temporary, then an impairment loss is recognized equal to the difference between the investment’s cost and its fair value.
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 their bylaws, operating margins, cash positions and various other factors. The Company recognizes capital 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.
Utility Plant
Utility plant is stated at the original cost of construction, including direct labor, materials, contracted services, payroll taxes and related payroll burdens, and overhead. 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.
Depreciation is provided on the following annual rates:
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. Prior to their sale in February 2004, the Company’s limited partner investment in real estate partnerships was included also. 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.
Income and expenses related to the Company’s primary real estate property are recognized on an accrual basis. The investments in real estate partnerships were accounted for under the cost basis method of accounting because the Company’s ownership was less than 10% in each case. Income from the Company’s miscellaneous real estate partnership investments is recognized as income was received. These investments were sold in February 2004.
Impairment of Long-Lived Assets
The Company’s policy is in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” whereby long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash inflows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount exceeds the fair value of the asset.
Goodwill and Intangible Assets
Goodwill is reviewed annually as of December 31 for impairment or whenever events and changes in circumstances occur that may reduce the fair value below the carrying value. No impairment has been necessary because the fair value of the recorded goodwill has exceeded the carrying value.
In connection with the conversion in 2002 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 provided for a due date of September 9, 2004, and because it was not certain that the Company would draw on the additional advance, the financing costs were being amortized over the 12 month period of the initial advance. The initial advance was repaid in November 2004. See also Note 12.
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 10.
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
As of December 31, 2001, the Cooperative’s equities and margins consisted only of amounts that were obligated to be converted into shareholder equity.
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 for 2003 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, were approximately $2,521,000, respectively.
Other operating revenue consists primarily of fees from customers for items such as late payment penalties and connection services, as well as building rental income which is accrued monthly based on contractual lease obligations.
Purchased Power Costs
The Company accrues its purchased power cost based on actual usage for the respective period.
The Company’s current tariffs for electric service include power cost recovery clauses under which electric rates charged to retail customers are adjusted monthly to collect actual purchased power costs incurred in providing service. The over or under collection is reflected in the balance sheet as Purchased power subject to recovery or refund. In connection with its review of the Company’s proposed tariffs for retail service, the PUCT may require the Company to change to a fixed fuel factor method for billing customers, subject to annual reconciliations of actual power cost incurred to actual fuel revenues collected.
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.
During the rate case proceedings in the fall of 2004, the Company determined that power costs of $3,074,000 had been overcollected under the Company’s retail tariffs through the power cost recovery process. A regulatory liability was recorded for this overcollection, and the over recovery was disclosed to the PUCT. These monies are currently being returned to customers through power cost recovery refunds. As of December 31, 2004, $480,000 had been returned to customers. Legal issues regarding this over recovery and the method and timing of refunding it are being discussed with the PUCT Staff, and the ultimate outcome is unknown. In addition, the Company believes rate case costs of $3,593,000 will be fully allowed, and this recovery will also offset the power cost recovery overcollection, making the payout to customers cash neutral, with no economic effect to the Company’s statement of operations. However, this is also subject to PUCT approval. See Note 22.
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 15.
Income Taxes
The Company accounts for 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. The Cooperative was dissolved in March 2004 and has filed a final 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, 2004 or 2003, no derivative position was held.
New Accounting Standards
In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment.” SFAS No. 123R revises SFAS No. 123, “Accounting for Stock-Based Compensation.” This new standard generally requires the cost associated with employee services received in exchange for an award of equity instruments be measured based on the grant-date fair value of the award and recognized in the financial statements over the period during which the employee is required to provide services in exchange for the award. SFAS No. 123R also provides guidance on how to determine the grant-date fair value for awards of equity instruments, as well as alternative methods of adopting its requirements. SFAS No. 123R is effective as of the beginning of the first interim or annual reporting period after June 15, 2005, and applies to all outstanding and unvested share-based payment awards at a company’s adoption date. 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, effective January 1, 2003. Therefore, SFAS No. 123R is not expected to have an impact on the Company’s consolidated financial statements.
In May 2004, the Financial Accounting Standards Board issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). FSP 106-2 permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Act and requires certain disclosures pending determination as to whether the sponsor’s postretirement health care plan reasonably expect to qualify for beneficial treatment under the Act. See Note 15 for quantification.
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 CONVERSION
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. 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. 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. The Cooperative was then dissolved in March 2004.
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.
4. 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.
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.
5. EARNINGS PER SHARE INFORMATION
The following table shows the reconciliation of basic and diluted earnings per share:
Both basic and diluted earnings per share for the year ended December 31, 2002, are not materially different.
6. OTHER CURRENT ASSETS
Other current assets as of December 31, 2004 and 2003, consisted of the following (in thousands):
7. INVESTMENTS AND NOTES RECEIVABLE
Investments and notes receivable as of December 31, 2004 and 2003, consisted of the following (in thousands):
Allocations of income from all associated organizations was $540,000, $530,000 and $478,000, respectively, for the years ended December 31, 2004, 2003 and 2002.
In October 2003, the Company sold its 42% interest in Map Resources, Inc. (“MAP”) to MAP in exchange for a note receivable of $1,250,000, due October 8, 2004, with interest at 6% per annum. The original investment had been accounted for using the equity method. The note receivable, shown in Current Notes Receivable at December 31, 2003, was 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 for 2003. The note was repaid in July 2004, and the Company recouped its original cash investment. The Company’s equity earnings in MAP for the nine month period ended September 30, 2003, and the year ended December 31, 2002, was $144,000 and $115,000, respectively.
In March 2004, the Company signed an agreement with a shareholder of United Fuel and Energy Corporation (“United Fuel”) to sell its shares of stock in that company for a sales price of $1,300,000 in exchange for a note receivable. The terms of the agreement provide: (a) interest on the note receivable at 6% annum, (b)
payment of $500,000 on the payment date plus accrued interest, (c) payment of the remaining principal balance in three equal annual installments plus accrued interest beginning one year after the payment date. The payment date is defined as the sooner of 24 months from the date of the agreement or 60 days after United Fuel has completed certain capitalization arrangements. Recognition of the gain of $940,000 has been deferred until principal payments have been received. See Note 16. All conditions required pursuant to the agreement have been satisfied, and the Company expects payment as scheduled in 2005.
The Company sold its limited partner interest in real estate partnerships in February 2004, to an unrelated third party in exchange for a note receivable of $286,000 due 2009, with interest at 4.5% per annum. The note is collateralized by the partnership interests. See Note 9.
8. UTILITY PLANT
Utility plant as of December 31, 2004 and 2003, consisted of the following (in thousands):
As of December 31, 2004 and 2003, all utility plant assets, except the transmission facilities, are pledged to collateralize debt and capital lease obligations.
9. NONUTILITY PROPERTY
Nonutility property as of December 31, 2004 and 2003, consisted of the following (in thousands):
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, 2004, 2003 and 2002, third party building rental revenue was $294,000, $258,000 and $286,000, 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, 2004 and 2003, the net book value of the building and related property was $1,112,000 and $1,141,000, respectively, which is the majority of the nonutility property.
The Company sold its limited partner interest in real estate partnerships in February 2004, to an unrelated third party in exchange for a note receivable of $286,000 which was collateralized by the partnership interests. There was no gain or loss recorded on the sale. 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.
10. REGULATORY AND OTHER ASSETS
Other assets as of December 31, 2004 and 2003, consisted of the following (in thousands):
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, 2004 and 2003, the accumulated amortization was $174,000.
Bank fees are costs of $210,000 incurred in connection with the conversion of the line of credit to a mortgage note. Accumulated amortization at December 31, 2004 and 2003, is $76,000 and $30,000. As of December 31, 2003, bank fees also included costs of $999,000 related to the refinancing of the transmission system with Beal Bank, S.S.B., with associated accumulated amortization of $333,000. These costs were fully amortized and retired because the loan was effectively repaid in November 2004. See also Notes 11 and 12.
Rate case costs are third party costs incurred to prepare the rate filing package, as well as the public hearing process. These costs are regulatory assets because the amount and period over which the Company will be allowed to recover these costs will be mandated by the PUCT. The PUCT is expected to rule on this matter in June 2005. See Note 22.
11. 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 from a member owned cooperative to a shareholder owned corporation, 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 as it concerned the conversion and notified the Company that all existing CFC indebtedness may remain in place with CFC after the conversion.
Substantially all of the CFC mortgage notes are subject to interest rate repricing at the end of various periods, at the Company’s option. Mortgage notes with CFC as of December 31, 2004 and 2003, consisted of the following (in thousands):
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, 2004, 2003 and 2002, was $21,000, $7,000 and $12,000, 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, 2004, are as follows (in thousands):
12. TRANSMISSION SYSTEM FINANCING
In connection with the original financing and construction of its transmission line, the Company entered into agreements qualified as capital lease obligations. As a result, the transmission line, substation assets and associated capital lease obligations were recorded on the Company’s consolidated financial statements.
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, which was due September 2003.
Regularly scheduled monthly principal payments on the transmission system capital lease obligation for the nine months ended September 30, 2003, and the year ended December 31, 2002, were approximately $3,556,000 and $5,047,000, 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, and the year ended December 31, 2002, was approximately $847,000 and $1,443,000, respectively, and is classified as purchased power cost consistent with ratemaking treatment.
FERC approval was received in August 2003 for NewCorp to borrow $31,500,000 from Beal Bank S.S.B. (“Beal Bank”). The initial advance of $14,169,000 was used for payment of the balloon payment on the transmission system capital lease in September 2003. Simultaneously, the sinking fund of $8,207,000 was released by the lessee, and used to partially fund a restricted securities account of $14,169,000, which was the only asset collateralized by Beal Bank.
Interest on the Beal Bank loan was 10.75%, payable monthly. The financing arrangement provided for a commitment fee, which totaled $457,000 for the initial advance. Additional amounts paid to Beal Bank were reimbursement of expenses, attorney fees, appraisals and consulting, which at December 31, 2004, aggregated $1,184,000. Prepayment of the initial advance was not allowed unless an additional advance was funded before the September 9, 2004, due date. In the accompanying consolidated balance sheet at December 31, 2003, the initial advance of $14,169,000 is shown in current liabilities because it was not certain that the Company would draw on the additional advance from Beal Bank. Two amendments to the financing agreement were executed which extended the due date of the initial advance. The collateralized cash investment was then used to repay the initial advance in November 2004.
13. NOTE PAYABLE AND OTHER CAPITAL LEASES
Previously, the Company had a note payable to a bank that was cross-collateralized by a note receivable from United Fuel and Energy Corporation (“United Fuel”). 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 was no longer a borrower and its involvement had been reduced to being a secondary guarantor for United Fuel’s note of $3,500,000. Generally accepted accounting principles required the Company to record a guarantee obligation that was measured at fair value. A guarantee obligation of $35,000 was recorded, based on factors such as asset collateralization value and guarantor hierarchy. United Fuel repaid the note in November 2004, effectively releasing the Company’s guaranty and the recorded guarantee obligation was then eliminated.
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):
14. ACCRUED AND OTHER CURRENT LIABILITIES
Accrued and other current liabilities at December 31, 2004 and 2003, consisted of the following (in thousands):
15. EMPLOYEE BENEFIT PLANS
Executive Deferred Compensation Plans
In November 2002, the Board approved an Executive Deferred Compensation Retirement 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. 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. For the years ended December 31, 2004 and 2003, $18,000 and $16,000 were contributed to the plan, and such amounts are shown as a liability on the consolidated balance sheets.
Stock Incentive Plan
The Company has a Stock Incentive Plan, approved by the shareholders, that provides for the granting of awards of common stock, options to purchase 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 for stock awards and the granting of options. Shares of common stock used to satisfy such awards will be acquired by the Plan either through open market purchases or through the issuance of additional common stock. For the years ended December 31, 2004, 2003 and 2002, the Company recorded
compensation expense of $4,925,000, $2,133,000 and $30,000, respectively, in connection with the fair value of these awards of common stock, of which $1,121,000, $113,000 and $0, respectively, were in the form of shares withheld by the Company, in order to remit cash payments for employees’ payroll tax withholding.
Employee Stock Purchase Plan
The Company has an Employee Stock Purchase Plan (“ESPP”), also approved by the shareholders, that provides its employees with the opportunity to purchase shares of its common stock through 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, 2004, the ESPP had not been implemented.
Stock for Compensation Plan
The Company has 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. This plan was also approved by the shareholders. 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, 2004, 2003 and 2002, cash bonuses of $6,000, $6,000 and $367,000, respectively, had been earned by individuals, who then were awarded shares of stock in lieu of the cash compensation.
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 two 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 $535,000, $527,000 and $481,000, for the years ended December 31, 2004, 2003 and 2002.
Other Postretirement Benefits
The Company provides continued major medical coverage to retired employees and their dependents. The cost to maintain such benefits for the years ended December 31, 2004, 2003 and 2002, totaled $235,000, $399,000 and $858,000, respectively.
The Medicare Reform Act of 2003 allows employers who sponsor a postretirement health care plan that provides a prescription drug benefit to receive a subsidy for the cost of providing that drug benefit. In order for employers to receive the subsidy payment under the Medicare Reform Act, the value of the offered prescription drug plan must be at least actuarially equivalent to the standard prescription drug coverage provided under Medicare Part D. The Company’s plan meets the actuarially equivalent test and qualifies for the subsidy. The reduction in current period service cost due to the subsidy was $34,000 for the year ended December 31, 2004, and the impact on the benefit obligation is $1,562,000.
The Company uses December 31 as a measurement date for the plan.
Obligations and Funded Status
The following tables set forth the obligations, fair value of plan assets and funded status at December 31, 2004 and 2003:
Components of Net Periodic Benefit Cost
The following sets forth the components of net periodic benefit cost for the years ended December 31, 2004, 2003 and 2002 (in thousands):
Actuarial Assumptions and Cost Trends
The following sets forth the assumptions used to determine benefit obligations:
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 (in thousands):
Plan Assets
No return on plan assets was assumed in the calculation as the Company holds no specified plan assets.
Future Benefit Payments
The following table provides estimates of future benefit payments, which reflect expected future service, as applicable (in thousands):
16. DEFERRED CREDITS
Deferred credits at December 31, 2004 and 2003, consisted of the following (in thousands):
17. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2004 and 2003. 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):
The book value of cash and cash equivalents approximated fair value because of the short maturity of those instruments. The carrying values of accounts receivable and account payable included in the accompanying consolidated balance sheets approximated market value at December 31, 2004 and 2003. As described in Note 11, the Company has both fixed rate and variable rate notes. The fair value of these mortgage notes is not able to be readily determined because there is no market for this type of debt.
18. MAJOR CUSTOMERS AND SUPPLIERS
For the years ended December 31, 2004, 2003 and 2002, the Company and its subsidiaries had no customer that accounted for more than 10% of operating revenues.
The Company utilizes an independent third party for its materials warehousing function. 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 22, Commitments and Contingencies.
19. 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 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. Because the Southwest Power Pool (“SPP”) does not have adequate infrastructure for customer choice, House Bill 1642 provides that the utilities in the SPP cannot participate in customer choice until 2007. Since the SPP still does not have adequate infrastructure for customer choice, it is expected that such date will be extended by the legislature. The majority of the Company’s service area is in the SPP, while approximately 25% is in ERCOT. While the PUCT could order the Company to bring its ERCOT territory into customer choice sooner than the law provides for customer choice to be provided by utilities in the SPP, such action would only serve to harm the Company’s customers and the Company does not believe the PUC will take such action. The Company believes the PUCT will be reasonable in developing appropriate schedules and procedures for the Company to enter into customer choice and that such action will not adversely affect the Company’s customers.
20. RELATED PARTY ACTIVITY
One of the compensation vehicles utilized by the Company was the Achievement Based Contract - Southwestern Public Service Company (“ABC-SPS”). The ABC-SPS contract provided 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 were the only remaining participants in the ABC-SPS contract, which expired in October 2003. For the years ended December 31, 2003 and 2002, compensation attributable to the contract was $126,000 and $156,000, respectively.
Two other compensation arrangements, the Achievement Based Compensation Contract - Merger or Acquisition with Other Electric Utilities, and the Achievement Based Compensation Agreement - Corporate Asset Non-CFC Financing Arrangements, were also in place in prior years. These compensation arrangements were cancelled in March 2005, and no amounts had been paid or accrued for the years ended December 31, 2004, 2003 and 2002.
21. 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, 2004 and 2003, there were 325,223 and 340,738 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.
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.
On December 31, 2004, the Trust and the Company entered into a Voting Agreement whereby the shares that are currently held in the Trust will be voted by the Trustees but as directed by the Company for so long as the shares are held in the Trust, or by the State in the event the shares escheat. As consideration, the Company will pay a 10% premium of the value of the shares as of December 30, 2004, to any owner of shares currently held in the Trust, at such time as the shares are issued to the legal owner or his or her heirs. At December 31, 2004, a liability based on fair value of $129,000 was recorded, and is shown as a long term liability in Deferred credits on the consolidated balance sheet. See Note 15.
22. COMMITMENTS AND CONTINGENCIES
The Company has various obligations to make future payments under contractual obligations:
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 is be based on the number of meters per respective month and, based on the number of meters at December 31, 2004, 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.
The Company has a contract with the City of Farmersville, Texas, to act as an agent 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 2005 and estimated 2006 annual payments are $621,000 and are reflected in the table under Other long term liabilities.
Purchased Power and Transmission Services. 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 2004. 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 aggregate cost of the contract with SPS for 2004 and 2003 was $27,322,000 and $23,114,000, respectively. 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.
Outsourced Functions. The Company utilizes an outside third party for its materials warehousing function. 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 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 $1,091,000 at December 31, 2004.
The Company has also outsourced its meter reading function. The basic terms of the contract provide for a fee per meter read, with the contract extended through 2008, unless either party gives 150 days written notice at any time.
PUCT Oversight and Decisions. Because of a change in the Public Utility Regulatory Act (“PURA”), as of September 1, 2003, the Company’s rates became subject to regulation and approval by the PUCT, not the Company’s Board of Directors. In accordance with this change in the PURA, the Company filed its tariffs for electric service on September 2, 2003. The staff of the PUCT reviewed those tariffs and provided comments and proposed changes to bring the tariffs into compliance with PUCT rules and regulations. Because the tariffs, when adopted, were not subject to PUCT regulation, some of the provisions did not comply with PUCT rules and
regulations since that was not a requirement when the tariffs were adopted. Now that the Company is subject to PUCT regulation, the Company made proposed amendments to its tariff as suggested by the PUCT staff. The PUCT staff reviewed the proposed changes and recommended that the tariff be approved. Prior to the Administrative Law Judge entering a ruling approving the tariff, with the proposed changes, several of the group of intervenors in the case were successful in obtaining a legislative request that the matter be referred to the State Office of Administrative Hearings (“SOAH”) for a hearing on the merits. As a result, the matter was referred to SOAH and a hearing is currently scheduled for April, 2005. The hearing will be limited to whether the tariffs filed by the Company are the actual tariffs that were properly approved by the Company’s Board of Directors, which was the Company’s previous regulatory authority. The Company believes the issue is moot because any current tariff will be superseded by the tariff that is ultimately approved by the PUCT in the rate case.
In October 2004, the PUCT initiated an inquiry to determine the reasonableness of the Company’s rates and ordered the Company to submit a rate filing package. The Company prepared and filed a rate filing package that contained a request for a rate increase for some customer classes. The Company initially requested a $6,333,000 overall annual after tax increase but due to adjustments made while preparing for the hearing on the merits in the case, that amount was adjusted downward to $5,021,000. Hearings were held before the State Office of Administrative Hearings from October 5, 2004, through October 14, 2004. During such hearings, the Company presented testimony and evidence in support of its requested rate increase. Numerous intervening parties and the PUCT staff presented evidence and testimony in opposition to the rate increase and in support of a rate decrease. The parties filed briefs in support of their positions and the Company has agreed to extend the effective date for the requested rate increase until June 17, 2005. A hearing was held in December 2004, to determine the amount of rate case costs that the PUCT will allow the Company to recover from its customers, as well as the period of recovery. The Company believes all of its rate case costs are reasonable and necessary and should be recoverable. Any amount not allowed for recovery will be expensed immediately. As of December 31, 2004, $3,593,000 of third party costs had been incurred in connection with the rate case, and are shown on the balance sheet as a regulatory asset because they were deferred pending approval of recovery by the PUCT.
On March 17, 2005, the Administrative Law Judges (“ALJ’s”) issued a Proposal for Decision (“PFD”). The PFD recommended a 7.49% rate decrease for Cap Rock. This amounts to an annual revenue decrease of approximately five million dollars. Several intervenors had sought rate decreases which were much larger than the recommendation of the ALJ’s. The recommendation by the ALJ’s will be considered by the PUCT at an open hearing. A final ruling, which can be appealed by Cap Rock or any of the intervenors, is expected by June 2005.
The Company feels that its rates and its requested small rate increase are justified and that its evidence support that. The Company will request that the PUCT reject the recommendation of the Administrative Law Judges and grant its requested rate increase. The Company has received recommendations from Administrative Law Judges in the past which were not in its favor, only to prevail when the issues were considered by the PUCT. 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 rate base. However, the Company cannot determine what action the PUCT will take with respect to the PFD.
If the Company’s request for a rate increase is approved by the PUCT, the Company may suffer a decline in its customer base. Because the outcome of the rate request or rate order is unknown until the PUCT makes a final ruling, the Company is unable to predict the effect of such ruling.
The Company determined during the rate case that power costs had been overcollected under the Company’s retail tariffs through the power cost recovery process. This was disclosed to the PUCT at that time. These monies are currently being returned to customers through power cost recovery refunds. This overcollection is partially
offset by a credit applied to power cost recovery due to the change in accounting principle to record revenues by the accrual method, rather than the as-billed method. Legal issues regarding this over recovery and the method of refunding it are being discussed with the PUCT staff and the ultimate outcome is currently unknown. The Company has recorded a liability for these costs. However, this is subject to PUCT approval.
The Company received two Notices of Violation (“NOV”) from the PUCT in September 2004. These NOV’s, which contain recommendations of the PUCT staff, are the result of changes in the Public Utility Regulatory Act (“PURA”) passed in 2003, which changed the way the Company was regulated. Prior to September 1, 2003, the Company’s rates were lawfully regulated by its Board of Directors, the same way all electric cooperatives in the state are regulated. During the 2003 legislative session, a small group of customers, who were opposed to the Company’s conversion from an electric cooperative to a shareholder owned corporation, were successful in getting the law changed so that the Company would be regulated by the PUCT instead of its Board of Directors. The changes, which took effect September 1, 2003, applied only to the Company and did not affect the way any other utility in the state is regulated.
The NOV’s cite the Company for charging late fees to residential customers who did not pay their bills on time, and for charging a regulatory surcharge to customers to recover costs incurred in a prior PUCT proceeding. Both of these charges were made in accordance with the Company’s tariff which had been adopted by its Board of Directors in accordance with Texas law at the time. Once the Company came under the regulatory authority of the PUCT on September 1, 2003, it filed those tariffs with the PUCT and the PUCT staff reviewed the tariffs and made recommendations to bring the tariffs into compliance with the rules and regulations of the PUCT and the PURA. The Company amended its tariffs to make all of their suggested changes and the proposed tariff, with the amendments, was filed and is currently awaiting approval by the PUCT. The charges for which the Company was cited relate to charges that were made under the Company’s legally adopted and approved tariff. The Company has filed a proposed tariff which complies with the PUCT rules and regulations, but due to actions of a small group of customers, this tariff has not yet been approved by the PUCT.
The NOV’s also recommend that the Company pay fines and customer refunds in excess of $1.3 million. These are the same claims that a small group of intervenors have been making in the Company’s PUCT tariff proceedings. Once the PUCT ruled that these allegations should not be considered with the Company’s tariff filing, they were made in these enforcement actions. The Company filed answers requesting a settlement conference with the PUCT staff and believed that the matters would be disposed of through that conference. However, a resolution was not reached and in early November the Company requested a hearing with the State Office of Administrative Hearings. The Company feels strongly about its legal position on these issues and believes it will ultimately prevail.
The PUCT has not yet established the procedures and time lines for the Company to comply with the other provisions of the PURA regarding investor owned utilities, including offering customer choice for customer power requirements. The Company anticipates that the PUCT will take relevant factors into consideration in establishing such procedures and time lines that are appropriate and such actions will not adversely effect the Company’s customers.
Lamar. Discovery is ongoing in the litigation involving the Company and Lamar Electric Cooperative Association, Inc. (“Lamar”) which arose out of Lamar’s termination of the Combination Agreement between Lamar and the Company in October 2002 and the Management Services Agreement in November 2002. Lamar filed suit against the Company in the 62nd 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 as
well as a cancellation fee of $300,000 for liquidated damages as set out in the terms of the Management Services Agreement.
In October 2004, the Company filed counterclaims against Lamar’s Board of Directors and two individual directors. The Company also joined several third parties alleging fraud, civil conspiracy and tortuous interference with business relations. Lamar has also amended its suit against the Company, adding claims for fraud and misrepresentation. It is likely there will be additional discovery on the new claims, and the matter will most likely not go to trial prior to the fourth quarter of 2005.
Other. The Company is involved in various litigation matters, none of which is expected to have a material impact on the financial condition, operating results or liquidity of the Company.
23. 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, 2004 and 2003 (in thousands):
The following is an analysis of consolidated income tax expense for the years ended December 31, 2004 and 2003 (in thousands):
The tax effects of significant temporary differences and carryforwards at December 31, 2004 and 2003, are as follows (in thousands):
As of December 31, 2004, the Company has net operating loss carryforwards of approximately $25.6 million. The net operating loss carryforwards are scheduled to expire in 2009 through 2024. The Company has a valuation allowance of $3,285,000 against the net deferred tax asset. This valuation allowance decreased $4,789,000 from 2003 to 2004 in part because of a change in temporary differences and the resulting net deferred taxes, and the changes in net operating losses between the two years. The Company had a capital loss carryforward of approximately $7.5 million which expired in 2004.
In early 2004, the IRS notified the Company that it intended to examine the federal income tax return of its Predecessor for the year 2001. The Company and the IRS are in the final stages of that process, and Management believes there will be no material impact on the Company’s financial position or results of operations.
24. 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, 2004, 2003 and 2002, is as follows (in thousands):
25. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes results for each of the four quarters in the years ended December 31, 2004 and 2003 (in thousands, except per share data):