CAP ROCK ENERGY CORP - 10-Q Quarterly Report

CAP ROCK ENERGY CORPORATION
Consolidated Statements of Operations
In thousands, except per share amounts
(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Operating revenues:
Electric sales	$	22,005		$	23,066		$	64,485		$	63,867
Other	347			277			1,022			1,070
Total operating revenues	22,352			23,343			65,507			64,937

Operating expenses:
Purchased power	13,472			10,532			31,958			30,030
Operations and maintenance	2,602			2,522			7,402			7,449
General and administrative	2,438			1,385			7,350			4,255
Depreciation and amortization	2,328			1,805			6,126			5,394
Property taxes	112			314			1,671			972
Other	62			38			190			282
Total operating expenses	21,014			16,596			54,697			48,382

Operating income	1,338			6,747			10,810			16,555

Other income (expense):
Allocation of income from associated organizations	539			530			539			530
Interest expense, net of capitalized interest	(1,831		)	(1,658		)	(5,536		)	(5,032		)
Loss on equity method investment value	—			(1,056		)	—			(1,061		)
Interest and other income	144			89			376			625
Equity earnings in MAP	—			66			—			144
Total other expense	(1,148		)	(2,029		)	(4,621		)	(4,794		)

Net income before income taxes	190			4,718			6,189			11,761

Income tax expense (benefit)	(658		)	80			250			1,457

Net income	$	848		$	4,638		$	5,939		$	10,304

Net income per common share:
Basic	$	.56		$	2.96		$	3.82		$	7.41
Diluted	$	.54		$	2.86		$	3.69		$	7.13

Weighted average number of common shares oustanding:
Basic	1,527,857			1,568,498			1,553,072			1,390,636
Diluted	1,584,172			1,623,796			1,609,387			1,445,934

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

CAP ROCK ENERGY CORPORATION

Consolidated Balance Sheets

(In thousands)

	September 30, 2004			December 31, 2003
	(unaudited)
ASSETS
Current assets:
Cash	$	22,493		$	12,170
Restricted cash investment	14,169			14,169
Accounts receivable:
Electric sales, net	8,882			8,500
Other	303			371
Note receivable	—			1,250
Other current assets	3,226			1,587
Total current assets	49,073			38,047

Investments and notes receivable	11,005			10,045
Utility plant, net	150,028			152,162
Nonutility property, net	1,234			1,545
Regulatory and other assets	2,986			1,190
Total Assets	$	214,326		$	202,989
LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Current portion of long-term debt	$	8,042		$	4,654
Short-term note payable	14,169			14,169
Accounts payable:
Purchased power	2,968			2,798
Other	2,828			2,679
Purchased power subject to refund	4,592			203
Accrued, other and regulatory liabilities	4,981			3,902
Current income tax payable	812			562
Total current liabilities	38,392			28,967

Long-term debt, net of current portion:
Mortgage notes	136,922			143,188
Note payable and other capital leases	173			184
Total long-term debt	137,095			143,372
Deferred credits	5,004			3,677
Stockholders’ equity:
Preferred stock, par value $1 per share, 50,000,000 shares authorized issued or outstanding	—			—
Common stock, par value $.01 per share, 50,000,000 shares authorized, 1,643,600 shares issued and 1,527,405 outstanding at September 30, 2004; 1,650,395 shares issued and 1,567,725 outstanding at December 31, 2003	16			17
Paid in capital	11,459			11,641
Retained earnings	25,913			19,974
Less Deferred compensation	(1,798		)	(3,826		)
Less Treasury stock of 116,195 and 82,670 shares, respectively at September 30, 2004, and December 31, 2003	(1,755		)	(833		)
Total stockholders’ equity	33,835			26,973
Total Liabilities and Stockholders’ Equity	$	214,326		$	202,989

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

CAP ROCK ENERGY CORPORATION

Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2004 and 2003

(In thousands)

(Unaudited)

	2004			2003
Cash Flows From Operating Activities:
Net income	$	5,939		$	10,304
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,126			8,393
Noncash stock compensation	1,846			1,148
Equity earnings in Map	—			(144		)
Loss on equity method investment value	—			1,056
Changes in:
Other assets/deferred credits	(1,275		)	(2,734		)
Accounts receivable	(314		)	(3,625		)
Purchased power cost subject to refund/recovery	4,389			2,074
Other current assets	(1,639		)	(1,161		)
Accounts payable and accrued expenses	1,648			1,083
Net cash provided by operating activities	16,720			16,394
Cash Flows From Investing Activities:
Utility plant additions, net	(3,161		)	(4,268		)
Additions/deletions to nonutility investments	(674		)	123
Collection of notes receivable	1,250			815
Net cash used in investing activities	(2,585		)	(3,330		)
Cash Flows From Financing Activities:
Payments on mortgage notes	(2,904		)	(2,803		)
Payments on other long-term debt and capital leases	(98		)	(18,537		)
Proceeds from note payable and capital leases	113			14,169
Restricted cash investment	—			(5,962		)
Repurchase/acquisition of common stock	(923		)	(852		)
Retirement of former member equity	—			(388		)
Net cash used in financing activities	(3,812		)	(14,373		)
Increase (Decrease) In Cash and Cash Equivalents	10,323			(1,309		)
Cash and Cash Equivalents:
Beginning of period	12,170			9,899
End of period	$	22,493		$	8,590
Noncash financing activities:
Deferred charges related to stock awards	$	—		$	4,566
Supplemental Cash Flow Information:
Cash paid during the period for interest	$	5,371		$	5,777
Cash paid during the period for income taxes	$	1,450		$	950

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

CAP ROCK ENERGY CORPORATION

Notes to Consolidated Financial Statements

1. Basis of Presentation

The accompanying consolidated financial statements include the accounts of the Registrant, Cap Rock Energy Corporation (the “Company”) and its wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management of Cap Rock Energy Corporation, the accompanying unaudited consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for the fair presentation of the Company’s financial position as of September 30, 2004 and 2003, and its consolidated results of operations and cash flows for the nine months ended September 30, 2004 and 2003. The consolidated results of operations for the three and nine months ended September 30, 2004, are not necessarily indicative of the results to be expected for the entire year. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K and the quarterly reports on Form 10-Q.

2. Basic and Diluted Weighted Average Number of Shares Outstanding

The table below shows the reconciliation between the basic and diluted weighted average number of common shares outstanding for the three and nine month periods ended September 30, 2004 and 2003:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003

Basic	1,527,857	1,568,498	1,553,072	1,390,636
Shares that have been deferred under the Stock for Compensation Plan	56,315	55,298	56,315	55,298
Diluted	1,584,172	1,623,796	1,609,387	1,445,934

The majority of the net increase in the number of basic shares from the 2003 periods to the 2004 periods is due to the awarding of stock to officers and directors of 302,500 shares, net of the repurchase of 82,140 shares through the tender offer.

3. Regulatory Assets and Liabilities

As of September 30, 2004, regulatory liabilities were composed of purchased power subject to refund of $1,518,000, excess recovery of costs of $723,000 incurred in connection with the Company’s response to Opposing Intervenors’ actions in the prior CCN case and $3,074,000 of overcollected power costs. These amounts are included in the balance sheet under the captions Purchased power subject to refund and Accrued, other and regulatory liabilities.

As of September 30, 2004 and 2003, regulatory assets of $2,462,000 and $173,000, respectively, were composed of costs paid to outside parties that were incurred in connection with the current rate case. Recovery of these costs will be determined by the PUCT and recovered from customers prospectively. See also Note 6. The Company believes it will be allowed to recover those costs. As of September 30, 2003, the regulatory asset also included purchased power subject to recovery of $1,427,000.

4. Income Taxes

Unlike the predecessor company, Cap Rock Energy Corporation is a taxable entity. One of it’s wholly-owned subsidiaries, NewCorp Resources Electric Cooperative, Inc. (NewCorp), is a tax-exempt cooperative under IRS Code Section 501(c)(12), and files a separate tax return. An income tax benefit of $658,000 and

$250,000 has been recorded for the three and nine months ended September 30, 2004, based upon the Company’s estimate of its ability to utilize its net operating loss carryforwards in future periods, as well as tax planning strategies available to realize the benefit of those tax loss carry-forwards. If the Company should elect not to implement those strategies, approximately $3.1 million of income tax expense would need to be provided in order to restore the deferred income taxes payable previously offset by the net operating losses. However, the Company fully intends to implement its strategy and realize the tax benefits.

As described in Notes 23 and 24 to the consolidated financial statements for December 31, 2003, included in the Company’s Form 10-K, the Company was notified by the IRS that it intended to examine the federal income tax return of its Predecessor for the year 2001. The IRS has commenced its audit process. The Company believes that its Predecessor and affiliates have adequately provided for its tax liabilities and does not anticipate any material impact to its earnings, cash flows or liquidity as a result of this review.

5. New Accounting Standards

On April 22, 2003, the FASB announced its decision to require all companies to expense the fair value of employee stock options. Companies will be required to measure the cost according to the fair value of the options. Although the new guidelines and ultimate measurement valuation methodology have not yet been released, it is expected that they will be finalized soon and will be effective for fiscal years beginning after June 30, 2005. As currently written, the proposed rules do not affect current stock compensation accounting of the Company. However, future issuances would be subject to the new rules and could be materially different from prior accounting.

In December 2003, the FASB issued Statement No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits (“SFAS No. 132R”), which retains the disclosure requirements in SFAS No. 132 and contains additional requirements. These additional requirements include disclosures about a plan sponsor’s investment strategies, detailed information of plan assets, expected future cash flow requirements, and interim disclosures related to periodic benefit cost.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) became law in the United States. The Medicare Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. In accordance with FASB Staff Position FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003,” the Company elected to defer recognition of the effects of the Medicare Act in any measures of the benefit obligation or cost.

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.

6. Contingencies

The Company is currently involved in a proceeding at the Public Utility Commission of Texas (“PUCT”) to determine the reasonableness of its retail rates. In that proceeding, 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 (“SOAH”) 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 and the Administrative Law Judges are expected to issue a Proposal for Decision by year end.

As of September 30, 2004, $2,642,000 of third party costs had been incurred in connection with the rate case, and are shown on the balance sheet as a regulatory asset. An additional $407,000 of expenditures has been incurred through October 31, 2004. A hearing has been scheduled for 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.

Once a Proposal for Decision is issued by the Administrative Law Judges, it will be considered by the PUCT and a final decision will be issued. A final ruling by the PUCT is expected to occur during the first quarter of 2005. The Company believes its rates are reasonable and that the requested rate increase is appropriate based upon its cost of service and reasonable return on its invested assets. However, the Company cannot determine what action the PUCT will take with respect to its current rates, its requested rate increase, or the Staff’s or intervenors’ proposals for rate decreases.

The Company determined during the rate case proceedings that power costs had been over collected under the Company’s retail tariffs through the power cost recovery process. This was disclosed to the PUCT at that time. Those monies are currently being returned to customers through power cost recovery refunds. This over collection 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 regulatory liability for those 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 the actions of a small group of intervenors, 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.

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 62^nd District Court in Lamar County, Texas, seeking a declaratory judgment that it had a right to terminate both agreements without regard to payment of any kind to the Company. The Company believes that Lamar’s stated reason for termination of the Combination Agreement does not fall within the specific allowable exceptions set forth in the agreement, and therefore the Company is seeking reimbursement of all costs and expenses incurred with regard to the attempted combination which amount to at least $1.4 million as well as a cancellation fee of $300,000 for liquidated damages as set out in the terms of the Management Services Agreement.

The Company recently 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.

7. Postretirement Benefits

The Company provides continued major medical insurance coverage to retired employees and their dependents. The components of net periodic benefit cost for the nine months ended September 30, 2004 and 2003 are as follow (in thousands):

	2004		2003
Service cost	$	161	$	155
Interest cost	388		378
Amortization of experience loss	244		246
Net periodic benefit cost	$	793	$	779

In its financial statements as of December 31, 2003, the Company disclosed that it expected to contribute $484,000 to its postretirement healthcare plan for 2004. As of September 2004, $235,000 of contributions have been made. The Company anticipates that it will make an additional contribution of $249,000 in the fourth quarter of 2004.

8. Short-term Note Payable

The Company’s transmission affiliate, NewCorp, had a loan arrangement with Beal Bank S.S.B. (“Beal Bank”) which was segregated into two advances. The initial advance of $14,169,000 was used in September 2003, for payment of a balloon payment on a capital lease associated with the transmission system. A restricted securities account in the same amount was collateral for the initial advance. The additional advance

of $17,331,000 was intended to provide funds for such items as working capital reserves, purchase of transmission assets, repayment of loans to another subsidiary and system upgrades and improvements.

The financing arrangement provided that either the initial advance was due September 9, 2004, or the additional advance be funded in September 2004. NewCorp and Beal Bank entered into two amendments extending the due dates of the initial advance to September 30, 2004, and then to October 29, 2004. Because of new lender conditions, NewCorp elected not to proceed with the additional advance, but instead elected to repay the initial advance on October 29, 2004, and used the funds from the collateralized restricted securities account to satisfy the debt payment.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Caution Regarding Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition and future operations. These statements, based on our expectation and estimates, are not guarantees of future performance and are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those expressed in the forward-looking statements. These risks, uncertainties and other factors include, but are not limited to:

• Weather conditions;

• Increased competition in the electric utility industry;

• 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, the pending rate and tariff proceedings, and the proceedings regarding the Notices of Violation;

• Changes in and compliance with environmental laws and policies;

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

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

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

• Changes in federal and state tax laws;

• The impact of changes in interest rates; and

• Unexpected changes in operating expenses and capital expenditures.

Our actual results may vary materially from those discussed in the forward-looking statements as a result of these and other factors. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Overview

Cap Rock Energy Corporation (“the Company”) is an electric distribution company operating in various non-contiguous areas in the State of Texas. The Company purchases power from wholesale suppliers and distributes that power to its retail customers over transmission and distribution lines. Effective September 1, 2003, Cap Rock Energy Corporation 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. NewCorp Resources Electric Cooperative, Inc. (“NewCorp”), a transmission affiliate of Cap Rock Energy Corporation, is subject to the oversight authority of the Federal Energy Regulatory Commission (“FERC”).

The Company’s significant accounting policies are described in Note 1 to the consolidated financial statements included in the Company’s annual Form 10-K for the year ended December 31, 2003, as well as in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Results of Operations

	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Operating Revenues:
Electric	$	22,005	$	23,066	$	64,485	$	63,867
Other	347		277		1,022		1,070
Total operating revenues	$	22,352	$	23,343	$	65,507	$	64,937

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, normally require residential customers to use more electricity in cooling their homes. Rural customers who irrigate crops use more electricity in the summer months for the irrigation process, and if the spring season didn’t bring much rain, these customers may irrigate sooner and longer. Portions of the Company’s service areas have been experiencing a severe long-term drought. The National Weather Service Climate Prediction showed only minimal relief for 2004.

Electric revenues decreased by $1,061,000 for the comparative three month periods, but increased $618,000 for the comparative nine month periods. This change is the result of the following major factors:

• An increase in power cost recovery revenues of $827,000 and $4,091,000 for the three and nine month periods, including recognition of deferred revenues of $546,000 and $1,638,000 respectively for those periods. The deferred revenue recognition for the 2003 periods related to purchased power expensed in prior years, but was recovered from customers over the 24 month period from January 2002 to December 2003;

• Decrease in revenue accruals of $1,240,000 and $3,477,000, respectively, for the three and nine month comparative periods, especially as it relates to the change in accounting principle in the first quarter of 2003;

• Increase in kWh sales of approximately $133,000 and $1,119,000, for the three and nine month periods;

• A regulatory surcharge of $954,000 and $1,428,000 for the 2003 three and nine month comparative periods, which related to recovery of intervention costs, caused a comparative decrease for 2004.

	Three Months Ended September 30,				Nine Months Ended September 30
	2004		2003		2004		2003
Operating Expenses:
Purchased power	$	13,472	$	10,532	$	31,958	$	30,030
Operations and maintenance	2,602		2,522		7,402		7,449
General and administrative	2,438		1,385		7,350		4,255
Depreciation and amortization	2,328		1,805		6,126		5,394
Property taxes	112		314		1,671		972
Other	62		38		190		282
Total operating expenses	$	21,014	$	16,596	$	54,697	$	48,382

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 $2,940,000 and $1,928,000 for the comparative three and nine month periods. The major changes are as follows:

• The conclusion of the rate making treatment of the capital lease payments associated with the transmission system in late 2003 caused a decrease in costs for the comparative three and nine month periods of $451,000 and $3,556,000, respectively. 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, this treatment is no longer applicable;

• Power costs and consumer consumption increased $281,000 and $2,349,000 for the three and nine month periods, respectively;

• Fuel cost related to the regulatory liability due to overcollection of power cost recovery of $3,074,000 for the 2004 periods.

Factors affecting operations and maintenance expenses are certain weather conditions such as high winds, ice storms and lightning, which cause damage to electric lines and interrupt service. Operations and maintenance expense increased $80,000 for the comparative three month periods, and decreased $47,000 for the comparative nine month periods because these activities have remained relatively static.

General and administrative expenses increased by $1,053,000 and $3,095,000 for the comparative three and nine month periods between 2004 and 2003, because of the following:

• Expensing of noncash stock awards to officers and directors caused a decrease of $547,000 for the three month comparative period, but an increase of $1,100,000 for the nine month comparative periods;

• Increased costs for the 2004 periods of $534,000 and $1,201,000 related to IT support and outsourced IT functions associated with the new fully integrated utility software application. These types of costs were not incurred in the 2003 periods.

Depreciation and amortization increased $523,000 and $732,000 for the three and nine month comparative periods. This is the net effect of the following components:

• Increase in the amortization of the fees and costs related to the Beal Bank financing arrangement of $257,000 and $772,000 for the three and nine month periods;

• Amortization of $367,000 in both of the 2004 periods of the costs associated with implementation of the new fully integrated software application;

• Conclusion of the rate making treatment in September 2003 of the amortization of property and equipment associated with the transmission system capital lease, which caused more of an increase for the three and nine month periods in 2004 of $89,000 and $400,000 respectively over 2003;

• Amortization of the fees and costs associated with the original transmission system capital lease of $184,000 and $740,000 are reflected in the three and nine month periods in 2003.

Initially the Company had anticipated that property tax expense for 2004 would increase materially because of current appraisal methodologies used in the ad valorem valuation of investor owned utilities in Texas as compared to the Company’s former cooperative status. Therefore, substantial increases were reflected in the first and second quarter. Although the Company has not yet received property tax statements from the applicable taxing authorities, it has monitored valuations and rates, and has revised its estimate of property tax expense downward $1,350,000 during the third quarter of 2004.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Other Income (Expenses)

Interest expense, net of capitalized interest	$	(1,831	)	$	(1,658	)	$	(5,536	)	$	(5,032	)
Interest and other income	144			89			376			625
Allocation of income from associated organizations	539			530			539			530
Loss on equity method investment value	—			(1,056		)	—			(1,061		)
Equity earnings in MAP	—			66			—			144
Total other income (expense)	$	(1,148	)	$	(2,029	)	$	(4,621	)	$	(4,794	)

Interest expense between the periods has increased $173,000 and $504,000, respectively, which is the net effect of three components:

• Increase in interest expense because of the new Beal Bank note of $292,000 and $1,062,000, respectively;

• Extinguishment of the note payable to a bank in September 2003, causing a decrease in the 2004 periods of $178,000 and $501,000, respectively;

• Slight reduction in the 2004 periods in interest rates on a portion of the mortgage debt, coupled with a reduction in the outstanding balance because of scheduled payments made.

Because the investment in MAP Resources was sold in the fourth quarter of 2003, there are no equity earnings to be recorded in the 2004 periods. Although the investment appreciated over the period that the Company held it, the sales price was less than the recorded book value of the investment on an equity method basis. Therefore, the Company was required to reflect a loss of $1,056,000.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004		2003
Income Tax Expense (Benefit):
Income tax expense (benefit)	$	(658	)	$	80	$	250	$	1,457

Income tax expense has increased or decreased because of the change in net taxable income between the periods. NewCorp’s net income is nontaxable, therefore the effective tax rate is less than the statutory tax rate.

Liquidity and Capital Resources

As of September 30, 2004, the Company had:

• Cash and cash equivalents of $22,493,000;

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

• Working capital of $10,681,000 and;

• Long-term indebtedness of $137,095,000, 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 normal operations. As of September 30, 2004, the Company had accumulated a cash balance it believes is sufficient to meet its current and short-term anticipated obligations, exclusive of the restricted cash investment which offsets the short term note payable.

Through 2001, one of the Company’s primary sources of capital and liquidity had been borrowings from CFC, the Company’s primary lender. These borrowings are collateralized by substantially all of the Company’s utility distribution assets. The existing long-term debt consists of a series of loans from CFC that impose various covenants. The Company is in compliance with all CFC loan covenants.

In December 2002, the Company elected to convert the interest rates on the majority of the mortgage notes from variable to fixed pursuant to the terms of the CFC loan agreements. These lock-ins of interest rates were done for one, two and three year periods. Substantially all of the CFC fixed rate notes are subject to interest rate repricing at the end of various periods.

Interest Rate		Repricing January	Amount (in thousands)
Fixed	3.05%	2005	$	6,543
Fixed	4.20%	2005	67,979
Fixed	4.70%	2006	33,299
Fixed	4.50%	2007	5,991
Fixed	4.30%	—	28,000
Fixed	7.00%	—	2
Variable	3.90%	—	3,001

Total mortgage debt			$	144,815

The weighted average interest rate at September 30, 2004, is 4.29%.

The initial advance from Beal Bank S.S.B. (“Beal Bank”) of $14,169,000, shown in the accompanying consolidated balance sheet as short-term note payable, was repaid in October 2004 through use of the collateralized restricted securities account. Because of new lender conditions, NewCorp elected not to proceed with the additional advance.

Regulatory Matters The Company is currently involved in a proceeding at the Public Utility Commission of Texas (“PUCT”) to determine the reasonableness of its retail rates. In that proceeding, 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 (“SOAH”) 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 and the Administrative Law Judges are expected to issue a Proposal for Decision by year end.

Deferred Tax Assets The Company has tax planning strategies available to realize the benefit of tax loss carryforwards. If the Company should elect not to implement those strategies, approximately $3.1 million of income tax expense would need to be provided, in order to restore the deferred income taxes payable previously offset by the net operating losses. However, the Company fully intends to implement its strategy and realize the tax benefits.

Item 3. 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. In recent years, the cost of natural gas, which is used as fuel to generate power, has increased substantially. The Company’s exposure to purchased power price risk is substantially mitigated because all actual costs of power are able to be recovered from billings to customers.

Credit Risk

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

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

The Beal Bank loan documents related to the restricted cash investment of $14,169,000 provide that the collateral may only be invested in US government securities, bank certificates of deposit, money market funds or other approved investments with varying terms of one year or less. When the Beal Bank

arrangement was terminated in October 2004, the restricted cash investment was used to satisfy the initial advance of $14,169,000.

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 was a secondary guarantor on a note to a bank for $3,500,000, and had recorded a guarantee obligation of $35,000 based upon the Company’s calculation of the fair value of the obligation. The note was repaid by the borrower in November 2004. It is anticipated that the bank will release the guarantee shortly and the Company will be able to eliminate the recorded obligation in the fourth quarter of 2004.

In its continued effort to focus on its core business, the Company sold its investment in MAP effective October 2003, in exchange for a note receivable of $1,250,000 due October 2004. In July 2004, MAP repaid the entire principal balance plus interest, and the Company released the original collateralized stock. The Company also sold its investments in real estate partnerships in February 2004, in exchange for a note receivable of $286,000 due in 2009. There was no gain or loss on the sale. The note is collateralized by the partnership interests.

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% per 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.

Interest Rate Risk

We are subject to market risk associated with interest rates on our CFC long-term indebtedness. The Company’s mortgage debt with CFC allows for a change from variable rate to fixed rate with no additional fees. In December 2002, the Company took advantage of favorable interest rates and converted its variable rate loans with CFC to fixed rate loans with staggered periods. As discussed above in Liquidity and Capital Resources, the notes are subject to repricing at the end of various periods. Mortgage notes of $6,543,000 with current interest rates of 3.05% are due to be repriced in January 2005, $67,979,000 with current interest rates of 4.20% are due to be repriced in January 2005, mortgage notes of $5,991,000 with current interest rates of 4.50% are due to be repriced in January 2007, mortgage notes of $33,299,000 with current interest rates of 4.70% are due to be repriced in January 2006, $3,001,000 of mortgage notes were repriced in January 2004 with a variable interest rate at September 30, 2004, of 3.90% and $28,000,000 of mortgage notes were repriced in January 2004 with an interest rate of 4.3% for the term of the note. A 1% change in interest rates would cause a change of $1,448,000 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 September 30, 2004, had a balance of $14,169,000. The terms of the Beal Bank loan documents provide that the collateral may only be invested in US Government securities, bank certificates of deposit, money market funds or other approved investments, with varying terms of one year or less. The weighted average interest rate for the investments for the three and nine months ended September 30, 2004, was less than one percent. The Beal Bank arrangement was terminated in October 2004.

Item 4. Controls and Procedures

At the date of this report, an evaluation was carried out, under the supervision and with the participation of management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities

Exchange Act of 1934. Based upon that evaluation, and in light of the new accelerated filing requirements mandated by the SEC, modifications were made to the disclosure controls and procedures to improve the flow and timeliness of information to the appropriate Company officials. These modifications will help ensure that the additional reporting requirements and the accelerated nature of the disclosure will be able to be addressed promptly and appropriately. The chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective, as modified, to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 6, “Contingencies,” to the consolidated financial statements.

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a) None

(b) None

ISSUER PURCHASES OF EQUITY SECURITIES
Period (2)	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share			(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that may yet be Purchased Under the Plans or Programs

July	31,655	(1)	$	28.67	(1)	n/a	n/a
August	—		—			n/a	n/a
September	—		—			n/a	n/a

(1) The Company repurchased 31,500 shares of stock that were owned and tendered by officers and directors to satisfy tax withholding obligations on the vesting of restricted shares. The purchase price was the closing price of the Company’s stock on the date of tender. In addition, 155 shares were repurchased from a departing employee at a premium over the closing price on the date of tender.

(2) The Company repurchased 1,715 shares during the period January 1, 2004 through June 30, 2004, at an average price of $35.61. These repurchases were from departing employees, at a premium over the closing price on the date of tender.

Item 3. Defaults Upon Senior Securities

None

TEXAS		75-2794300
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S Employer Identification No.)

500 West Wall Street, Suite 400, Midland, Texas		79701
(Address of Principal Executive Offices)		(Zip Code)

Item 1. Financial Statements

Consolidated Statements of Operations – Three and nine months ended September 30, 2004 and 2003

Consolidated Balance Sheets – September 30, 2004 and December 31, 2003

Consolidated Statements of Cash Flows – Nine months ended September 30, 2004 and 2003

Notes to Consolidated Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Item 4. Controls and Procedures

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Item 3. Defaults Upon Senior Securities

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

Item 5. Other Information

Item 6. Exhibits

Exhibits:

31.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).

31.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).

32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer).

32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer).

		CAP ROCK ENERGY CORPORATION


November 18, 2004
		/s/ Lee D. Atkins
		Lee D. Atkins
		Senior Vice President,
		Chief Financial Officer and Treasurer

Exhibit Number		Description of Document

31.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer). *

31.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer). *

32.1		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive Officer). *

32.2		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial Officer). *