UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

or

Commission File Number:     0-20100

BELDEN & BLAKE CORPORATION

(330) 499-1660

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

     Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [  ] Yes [X] No

     As of November 10, 2004, Belden & Blake Corporation had outstanding 1,500 shares of common stock, without par value, which is its only class of stock.

BELDEN & BLAKE CORPORATION

INDEX

BELDEN & BLAKE CORPORATION

See accompanying notes.

1

BELDEN & BLAKE CORPORATION

See accompanying notes.

2

BELDEN & BLAKE CORPORATION

See accompanying notes.

3

BELDEN & BLAKE CORPORATION

See accompanying notes.

4

BELDEN & BLAKE CORPORATION

September 30, 2004

(1) Merger

     Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation and its subsidiaries. On July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”), and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C’s general partner is Capital C Energy, LLC, an entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and Peter R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power Fund II, L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered in Houston, Texas.

     The Merger was completed on July 7, 2004 and for financial reporting purposes was accounted for as a purchase effective July 1, 2004. The Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to July 1, 2004 are presented on the Company’s new basis of accounting, while the results of operations for the periods ended July 1, 2004 and June 30, 2003 reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies.

     In the Merger, each issued and outstanding share of the Company’s common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under the Company’s prior credit facility were repaid. In connection with the Consent Solicitation and Tender Offer previously announced by the Company, over 98% of the Company’s $225 million aggregate principal amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the closing of the Merger. As of September 30, 2004, all of the $225 million aggregate principal amount has been paid.

     Capital C obtained the funds necessary to consummate the Merger through (1) equity capital contributions of $77.5 million by its partners, (2) the Company’s entry into a secured credit facility with various lenders arranged through Goldman Sachs Credit Partners, L.P. with a $100 million term facility maturing on July 7, 2011, a $30 million revolving facility maturing on July 7, 2010 and a $40 million letter of credit facility, which amounts are secured by substantially all of the assets of the Company and are guaranteed by two of the Company’s subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas Company (the “Senior Facilities”), with the two subsidiaries’ stock pledged as collateral and (3) a private placement of $192.5 million aggregate principal amount of 8.75% Senior Secured Notes due 2012 (the “Notes”), which are secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities. Pre-existing commodity hedges and ten-year commodity hedges effected in connection with the Merger were also secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes.

5

     The table below summarizes the preliminary allocation of the purchase price based on the acquisition date fair values of the assets acquired and the liabilities assumed. The purchase price allocation is preliminary because the determination of fair values of certain assets and liabilities as of the acquisition date have not been completed.

     In connection with the Merger we entered into commodity hedges on a substantial portion of our future oil and gas production through the year 2013. See Note 5.

     Our management team remained after the Merger with the exception of the retirement of the former Chief Executive Officer, John L. Schwager. Frost W. Cochran is the Company’s new President and Chief Executive Officer. In addition, B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice Presidents. Upon consummation of the Merger all former directors of the Company resigned and the new Board of Directors consisted of six members, each of whom is elected annually to serve one-year terms. The initial six members of the Board of Directors were Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard. On November 1, 2004, James A. Winne III and Michael Becci were elected to our Board of Directors and were also named Senior Vice Presidents of the Company. Their election brings the Board’s membership to eight.

     Following are unaudited pro forma results of operations as if the Merger occurred at the beginning of 2003 (in thousands):

     The unaudited pro forma information presented above assumes the transaction-related expenses were incurred prior to the period presented and does not purport to be indicative of the results that actually would have been obtained if the merger had been consummated at the beginning of 2003 and is not intended to be a projection of future results or trends. In connection with the Merger, we entered into a management services agreement with Capital C, pursuant to which Capital C, initially Frost W. Cochran, B. Dee Davis and W. Mac Jensen, provides certain management and advisory services to us for a quarterly fee of $250,000. These services include general management supervision and oversight, in the capacity as officers of Belden & Blake; financial advisory services; evaluation of potential acquisitions and other business opportunities; and strategic consulting services. This agreement will be in effect until July 7, 2014 unless otherwise terminated due to the sale of substantially all of our assets, or our dissolution and winding up of our business.

     Carlyle/Riverstone or an affiliate received a fee from us of approximately $1.4 million in connection with the Merger.

6

(2) Basis of Presentation

     The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the successor company for the 91 day period from July 2, 2004 to September 30, 2004 and the predecessor company for the 183 day period from January 1, 2004 are not necessarily indicative of the results that may be expected for the year ended December 31, 2004. For further information, refer to the consolidated financial statements and footnotes included in our annual report on Form 10-K for the year ended December 31, 2003. Certain reclassifications have been made to conform to the current presentation.

     We incurred transaction costs associated with the Merger of $21.2 million. These costs were expensed in the predecessor company period ended July 1, 2004. We also capitalized $12.0 million of debt financing costs. The change in fair value of $2.4 million of certain hedges from July 1, 2004 to July 7, 2004 was recorded in “Derivative fair value loss” in the predecessor company period ended July 1, 2004. Income tax benefits of $5.1 million were recorded in the one day predecessor company period ended July 1, 2004.

(3) New Accounting Pronouncements

     In 2003, we were made aware of an issue regarding the application of provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 141, “Business Combinations” and SFAS 142, “Goodwill and Other Intangible Assets,” to oil and gas companies. The issue was whether SFAS 142 required registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, “Disclosures about Oil and Gas Producing Activities.”

     This matter was referred to the Emerging Issues Task Force (EITF) in late 2003. Although the EITF has not issued formal guidance for oil and gas companies, at the March 2004 meeting, the EITF reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. In order to resolve this inconsistency, the FASB directed the FASB staff to prepare a FASB Staff Position (FSP) that amended SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first reporting period beginning after April 29, 2004. Since we already include these assets as part of our capitalized oil and gas properties, the application of this FSP did not have an impact.

(4) Dispositions and Discontinued Operations

     On June 25, 2004, we completed a sale of substantially all of our Trenton Black River (“TBR”) assets to Fortuna Energy Inc., a wholly owned subsidiary of Talisman Energy Inc. The assets sold include working interests in 16 wells, approximately 11 miles of natural gas gathering lines and oil and gas leases on approximately 475,000 gross acres. The assets are located primarily in New York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for approximately 5 Bcfe of our estimated proved reserves as of December 31, 2003.

     The sale resulted in proceeds of approximately $68.4 million. The proceeds were used to pay down our existing revolving credit facility. As a result of the disposition of the TBR geographical/geological pools, we recorded a gain of approximately $46.3 million ($29.5 million net of

7

tax) in June 2004. According to SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition was classified as discontinued operations.

     In April 2004, we decided to dispose of our Arrow Oilfield Service Company (“Arrow”) assets. We sold the Michigan assets of Arrow in May 2004 and sold the Ohio and Pennsylvania assets of Arrow in June 2004. The two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a result of the disposition of all of its Arrow assets, we recorded a loss of approximately $1.3 million ($839,000 net of tax) in the second quarter of 2004. According to SFAS 144, the disposition of the Arrow assets was classified as discontinued operations.

(5) Derivatives and Hedging

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. We recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not qualifying for designation as cash flow hedges that occur prior to maturity are initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. All amounts recorded in this line item are ultimately reversed within the same line item and included in oil and gas sales revenues over the respective contract terms. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss).

     The relationship between the hedging instruments and hedged item must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness at least on a quarterly basis. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

     From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility and support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At September 30, 2004, our derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that we believe is a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

     We consider our natural gas swaps to be highly effective and expect there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. We have not experienced ineffectiveness on our natural gas swaps because we use NYMEX based commodity derivative contracts to hedge on the same basis as our natural gas production is sold (NYMEX based sales contracts). We have collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 1, 2004. Our NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The changes

8

in the fair values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded as “Derivative fair value gain or loss.”

     During the first nine months of 2004 and 2003, a net loss of $13.4 million ($8.5 million after tax) and a net loss of $9.7 million ($6.2 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges decreased $58.2 million ($36.9 million after tax) in the first nine months of 2004 and decreased $19.3 million ($12.3 million after tax) in the first nine months of 2003. At September 30, 2004, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $6.7 million. At September 30, 2004, we have partially hedged our exposure to the variability in future cash flows through December 2013. See Note 1.

9

     The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at September 30, 2004:

(1) The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00. The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90.

(6) Stock-Based Compensation

     We measure expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. (APB) 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant.

     For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of the options is amortized to expense over the options’ vesting period. The changes in net income or loss as if we had applied the fair value provisions of SFAS 123 for the predecessor company for the 183 day period from January 1, 2004 to July 1, 2004 and three and nine months ended September 30, 2003 were not material. The successor company does not have any stock options.

10

     The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The vesting of shares in the predecessor company quarter ended September 30, 2003, resulted in a non-cash increase in compensation expense of $36,000. The successor company does not have any stock-based compensation.

(7) Industry Segment Financial Information

     We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.

(8) Supplemental Disclosure of Cash Flow Information

(9) Contingencies

     In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by the successor in interest to these royalty interests, alleging substantially the same underpayments. We believe there will be no material amount payable above and beyond the amount accrued as of September 30, 2004 and therefore, the result will have no material adverse effect on our financial position, results of operations or cash flows.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Information

     The information in this document includes forward-looking statements that are made pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “will,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” and variations of these statements and similar expressions are forward-looking statements. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements and our business prospects are subject to a number of risks and uncertainties, which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or

11

regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in our 10-K and 10-Q reports and other filings with the Securities and Exchange Commission (“SEC”).

Critical Accounting Policies

     We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“GAAP”) and SEC guidance. See the “Notes to Consolidated Financial Statements” included in “Item 8. Financial Statements and Supplementary Data” in our 2003 Form 10-K annual report filed with the SEC for a comprehensive discussion of our significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of our most critical accounting policies:

Successful Efforts Method of Accounting

     The accounting for and disclosure of oil and gas producing activities requires management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties.

     We utilize the “successful efforts” method of accounting for oil and gas producing activities as opposed to the alternate acceptable “full cost” method. Under the successful efforts method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining unproved properties, are expensed as incurred.

     The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense.

Oil and Gas Reserves

     Our proved developed and proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. The accuracy of a reserve estimate is a function of:

--		the quality and quantity of available data;
--		the interpretation of that data;
--		the accuracy of various mandated economic assumptions; and
--		the judgment of the persons preparing the estimate.

     The proved reserve information included in our 2003 Form 10-K is based on estimates prepared by independent petroleum engineers. Estimates prepared by others may be higher or lower than these estimates.

12

Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets

     See the “Successful Efforts Method of Accounting” discussion above. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

     Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense.

     Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

     Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.

     Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined on management’s outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property.

Derivatives and Hedging

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. We recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not qualifying for designation as cash flow hedges that occur prior to maturity are initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. All amounts recorded in this line item are ultimately reversed within the same line item and included in oil and gas sales revenues over the respective contract terms. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss).

     The relationship between the hedging instruments and hedged item must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness at least on a quarterly basis. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). If there is a

13

discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

     From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility and support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At September 30, 2004, our derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that we believe is a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

     We consider our natural gas swaps to be highly effective and expect there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. We have not experienced ineffectiveness on our natural gas swaps because we use NYMEX based commodity derivative contracts to hedge on the same basis as our natural gas production is sold (NYMEX based sales contracts). We have collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 1, 2004. Our NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The changes in the fair values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

     Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes.

New Accounting Pronouncements

     In 2003, we were made aware of an issue regarding the application of provisions of SFAS 141, “Business Combinations” and SFAS 142, “Goodwill and Other Intangible Assets,” to oil and gas companies. The issue was whether SFAS 142 required registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, “Disclosures about Oil and Gas Producing Activities.”

     This matter was referred to the EITF in late 2003. Although the EITF has not issued formal guidance for oil and gas companies, at the March 2004 meeting, the EITF reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. In order to resolve this inconsistency, the Board directed the FASB staff to prepare a FSP that amended SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first reporting period beginning after April 29, 2004. Since we already include these assets as part of our capitalized oil and gas properties the application of this FSP will not have an impact.

Results of Operations

     As disclosed in the accompanying notes to consolidated financial statements, the Merger was completed on July 7, 2004 and for financial reporting purposes was accounted for as a purchase effective July 1, 2004. The Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to July 1, 2004

14

are presented on the Company’s new basis of accounting, while the results of operations for the periods ended July 1, 2004 and June 30, 2003 reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies.

     The allocation of the purchase price at fair value resulted in a significant increase in the book value of our assets. In conjunction with the Merger, we recorded an additional $121 million to oil and gas properties as a result of the deferred tax liability for the difference between the tax basis and the book basis attributed to the properties under the purchase method of accounting. The increase in the book value of assets resulted in materially higher charges for depreciation, depletion and amortization in the successor company period ended September 30, 2004. These higher charges are expected to continue in subsequent accounting periods.

     We incurred transaction costs associated with the Merger of $21.2 million. These costs were expensed in the predecessor company period ended July 1, 2004. We also capitalized $12.0 million of debt financing costs. The change in fair value of $2.4 million of certain hedges from July 1, 2004 to July 7, 2004 was recorded in “Derivative fair value loss” in the predecessor company period ended July 1, 2004. Income tax benefits of $5.1 million were recorded in the one day predecessor company period ended July 1, 2004.

     The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, discontinued operations have been excluded. As a result of the Merger, the results of operations for the periods subsequent to July 1, 2004 are not necessarily comparable to those prior to July 1, 2004. The following table combines the predecessor company period from January 1, 2004 to July 1, 2004, with the successor company period from July 2, 2004 to September 30, 2004, for purposes of the discussion of year-to-date. The discussion of third quarter results include the one day predecessor company period ended July 1, 2004. The following table sets forth certain information regarding our net oil and natural gas production, revenues and expenses for the periods indicated:

Third Quarters of 2004 and 2003 Compared

Revenues

     Net operating revenues decreased from $24.0 million in the third quarter of 2003 to $23.8 million in the third quarter of 2004. The decrease was due to lower gas sales revenues of $207,000 and lower gas

15

gathering and marketing revenues of $260,000, partially offset by higher oil sales revenues of $348,000.

     Gas volumes sold were 3.8 Bcf (billion cubic feet) in the third quarter of 2004, which was a decrease of 37 Mmcf (1%) compared to the third quarter of 2003. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $180,000. Oil volumes sold decreased approximately 10,000 Bbls (10%) from 103,000 Bbls in the third quarter of 2003 to 93,000 Bbls in the third quarter of 2004 resulting in a decrease in oil sales revenues of approximately $280,000. The lower gas sales volumes are due to normal production declines, partially offset by production from new wells drilled during 2004. The lower oil sales volumes are due to normal production declines. Our drilling program primarily targets natural gas reserves.

     The average price realized for our natural gas was consistent in the third quarter of 2004 compared to the third quarter of 2003 at $4.87 per Mcf. As a result of our hedging activities, gas sales revenues were decreased by $4.2 million ($1.10 per Mcf) in the third quarter of 2004 and decreased by $1.1 million ($0.30 per Mcf) in the third quarter of 2003. The average price realized for our oil increased from $27.57 per Bbl in the third quarter of 2003 to $34.28 per Bbl in the third quarter of 2004, which increased oil sales revenues by approximately $630,000. As a result of our hedging activities, oil sales revenues were decreased by approximately $578,000 ($6.19 per Bbl) in the third quarter of 2004.

     The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis remained consistent at $3.57 per Mcfe in the third quarter of 2004 compared to the third quarter of 2003. The average price increased $0.15 per Mcfe which was offset by an increase in production expense of $0.14 per Mcfe and an increase in production taxes per Mcfe of $0.01 in the third quarter of 2004 compared to the third quarter of 2003.

     The decrease in gas gathering and marketing revenues was due to a $216,000 decrease in gas marketing revenues and a $42,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues resulted primarily from lower gas volumes from third party wells.

Costs and Expenses

     Production expense increased $520,000 (10%) from $5.0 million in the third quarter of 2003 to $5.5 million in the third quarter of 2004 primarily due to an increase in labor resulting from continued well development activities, an increased focus on production and compressor optimization and a general increase in fuel and power costs. The average production cost increased from $1.12 per Mcfe in the third quarter of 2003 to $1.26 per Mcfe in the third quarter of 2004. The per unit increase was due to the higher costs and lower volumes discussed above.

     Production taxes increased $35,000 from $615,000 in the third quarter of 2003 to $650,000 in the third quarter of 2004. Average per unit production taxes increased from $0.14 per Mcfe to $0.15 per Mcfe. The increased production taxes are primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

     Exploration expense decreased $115,000 (8%) from $1.4 million in the third quarter of 2003 to $1.3 million in the third quarter of 2004. This decrease is primarily due to lower exploratory dry hole expense as we have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling.

     General and administrative expense was consistent at $1.1 million in the third quarter of 2003 and in the third quarter of 2004.

     Depreciation, depletion and amortization increased by $4.2 million from $4.4 million in the third

16

quarter of 2003 to $8.6 million in the third quarter of 2004. This increase was primarily due to an increase in depletion expense. Depletion expense increased $4.4 million (124%) from $3.6 million in the third quarter of 2003 to $8.0 million in the third quarter of 2004 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.80 per Mcfe in the third quarter of 2003 to $1.83 per Mcfe in the third quarter of 2004, primarily due to a higher cost basis resulting from purchase accounting for the Merger in the third quarter of 2004. Approximately $0.44 per Mcfe of the increase in depletion per Mcfe was due to the $121 million deferred tax gross-up to producing oil and gas properties.

     Derivative fair value loss was $340,000 in the third quarter of 2003 compared to a loss of $6.1 million in the third quarter of 2004. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $1.6 million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which was recorded in the third quarter of 2004.

     Interest expense increased $421,000 from $5.7 million in the third quarter of 2003 to $6.1 million in the third quarter of 2004. This increase was due to an increase in average outstanding borrowings partially offset by lower blended interest rates.

     Income tax expense decreased $9.2 million from $1.0 million in the third quarter of 2003 to a benefit of $8.2 million in the third quarter of 2004. The decrease was due to a decrease in income from continuing operations before income taxes coupled with a lower effective tax rate in the third quarter of 2004. The effective tax rate was reduced due to certain nondeductible transaction-related expenses recorded in the one-day predecessor period. The tax rate was also impacted by the redetermination of deferred taxes under purchase accounting and the resulting impact on deferred tax expense during the third quarter of 2004. The state effective rate is also impacted by income in a low tax rate state offset by losses in a higher tax rate state.

     Discontinued operations relating to the TBR and Arrow asset sales resulted in a loss, net of tax, of $449,000 in the third quarter of 2004 compared to a loss, net of tax, of $3.6 million in the third quarter of 2003. This was primarily attributable to $4.7 million of exploration expense incurred in the third quarter of 2003. The TBR properties were sold in the second quarter of 2004.

Nine Months of 2004 and 2003 Compared

Revenues

     Net operating revenues increased from $70.1 million in the first nine months of 2003 to $74.2 million in the first nine months of 2004. The increase was due to higher gas sales revenues of $3.8 million and higher oil sales revenues of $916,000 partially offset by lower gas gathering and marketing revenues of $698,000.

     Gas volumes sold increased 635 Mmcf (6%) from 10.9 Bcf in the first nine months of 2003 to 11.5 Bcf in the first nine months of 2004 resulting in an increase in gas sales revenues of approximately $3.1 million. Oil volumes sold decreased approximately 24,000 Bbls (8%) from 306,000 Bbls in the first nine months of 2003 to 282,000 Bbls in the first nine months of 2004 resulting in a decrease in oil sales revenues of approximately $680,000. The gas sales volume increase was primarily due to the production from wells drilled in 2003 and 2004 and increased production as a result of additional expenditures to stimulate production on declining wells partially offset by normal production declines. The lower oil sales volumes are due to normal production declines. Our drilling program primarily targets natural gas reserves.

     The average price realized for our natural gas increased $0.06 per Mcf to $5.00 per Mcf in the first nine months of 2004 compared to the first nine months of 2003, which increased gas sales revenues

17

in the first nine months of 2004 by approximately $690,000. As a result of our hedging activities, gas sales revenues were decreased by $12.6 million ($1.10 per Mcf) in the first nine months of 2004 and decreased by $9.7 million ($.89 per Mcf) in the first nine months of 2003. The average price paid for our oil increased from $28.07 per Bbl in the first nine months of 2003 to $33.73 per Bbl in the first nine months of 2004, which increased oil sales revenues by approximately $1.6 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $578,000 ($2.05 per Bbl) in the first nine months of 2004.

     The operating margin from oil and gas sales on a per unit basis increased from $3.62 per Mcfe in the first nine months of 2003 to $3.68 per Mcfe in the first nine months of 2004. The average price increased $0.18 per Mcfe which was partially offset by an increase in production expense of $0.12 per Mcfe in the first nine months of 2004 compared to the first nine months of 2003.

     The decrease in gas gathering and marketing revenues was due to a $1.2 million decrease in gas marketing revenues partially offset by a $535,000 increase in gas gathering revenues. The lower marketing revenues were primarily the result of decreased gas volumes from third party wells. The increase in gas gathering revenues was primarily due to higher margins on a gathering system in Pennsylvania.

Costs and Expenses

     Production expense increased $2.2 million (15%) from $14.3 million in the first nine months of 2003 to $16.5 million in the first nine months of 2004 primarily due to an increase in labor resulting from continued well development activities, an increased focus on production and compressor optimization, a general increase in fuel and power costs and $462,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of our stock. The average production cost increased from $1.13 per Mcfe in the first nine months of 2003 to $1.25 per Mcfe in the first nine months of 2004. The per unit increase was primarily due to the higher costs discussed above partially offset by certain fixed costs spread over greater volumes in the first nine months of 2004. The non-cash stock-based compensation expense was $0.04 per Mcfe of the per unit increase. Production taxes increased $7,000 in the first nine months of 2004.

     Exploration expense decreased $639,000 (14%) from $4.7 million in the first nine months of 2003 to $4.1 million in the first nine months of 2004 primarily due to a decrease in exploratory dry hole expense partially offset by additional non-cash stock-based compensation expense recorded in the second quarter of 2004. We have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling.

     General and administrative expense increased $231,000 (7%) from the first nine months of 2003 to the first nine months of 2004 due to $292,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of our stock partially offset by decreases in other employment and compensation related expenses.

     Depreciation, depletion and amortization increased by $5.1 million from $12.6 million in the first nine months of 2003 to $17.7 million in the first nine months of 2004. This increase was primarily due to an increase in depletion expense. Depletion expense increased $5.3 million (54%) from $10.0 million in the first nine months of 2003 to $15.3 million in the first nine months of 2004 due to higher gas volumes and a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.79 per Mcfe in the first nine months of 2003 to $1.16 per Mcfe in the first nine months of 2004, primarily due to a higher cost basis resulting from purchase accounting for the Merger in the third quarter of 2004. Approximately $0.15 per Mcfe of the increase in depletion per Mcfe was due to the $121 million deferred tax gross-up to producing oil and gas properties.

18

     Derivative fair value loss was $166,000 in the first nine months of 2003 compared to $5.8 million in the first nine months of 2004. The derivative fair value loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $1.6 million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which was recorded in the third quarter of 2004.

     Interest expense increased $664,000 (4%) from $17.7 million in the first nine months of 2003 to $18.3 million in the first nine months of 2004. This increase was due to an increase in average outstanding borrowings partially offset by lower blended interest rates.

     Income tax expense decreased $8.4 million from $2.8 million in the first nine months of 2003 to a benefit of $5.6 million in the first nine months of 2004. The decrease was due to a decrease in income from continuing operations before income taxes coupled with a lower effective tax rate in the nine month period of 2004. The effective tax rate was reduced due to certain nondeductible transaction-related expenses recorded in the one-day predecessor period. The tax rate was also impacted by the redetermination of deferred taxes under purchase accounting and the resulting impact on deferred tax expense during the third quarter of 2004. The state effective tax rate is also impacted by income in a low tax rate state offset by losses in a higher tax rate state.

     Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.2 million in the first nine months of 2004 compared to a loss, net of tax, of $4.8 million in the first nine months of 2003. This was primarily attributable to the $45.0 million ($28.6 million net of tax) gain recorded in the second quarter of 2004 and decreased exploration expense as a result of the sale of the TBR properties in the second quarter of 2004.

Liquidity and Capital Resources

Cash Flows

     The primary sources of cash in the nine-month period ended September 30, 2004 have been net proceeds from the sale of our TBR and Arrow assets, funds generated from operations and from borrowings under our credit facilities, the merger and proceeds from our 8.75% Senior Secured Notes. Funds used during this period were primarily used for operations, exploration and development expenditures, interest expense, merger expenses and repayment of debt. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

     Our operating activities provided cash flows of $32.9 million during the first nine months of 2004 compared to $20.7 million in the first nine months of 2003. The increase was primarily due to higher oil and gas margins (net of hedging) of $2.6 million and changes in working capital items of $6.6 million.

     Cash flows used in investing activities increased in the first nine months of 2004 primarily due to $4.5 million of increased capital expenditures in the first nine months of 2004.

     Cash flows used in financing activities in the first nine months of 2004 were primarily due to the Merger and payments on the predecessor company credit facility. Cash flows provided by financing activities during the first nine months of 2003 were borrowings on the credit facility to fund acquisition, exploration and development expenditures in the first nine months of 2003.

     Our current ratio from continuing operations at September 30, 2004 was 0.80 to 1. During the first nine months of 2004, the working capital from continuing operations decreased $4.3 million from a deficit of $7.1 million at December 31, 2003 to a working capital deficit of $11.4 million at September 30, 2004. The decrease was primarily due to a $18.6 million increase in the net current liability for the

19

fair value of derivatives, a $7.3 million increase in accrued expenses and a $3.3 million decrease in the deferred income taxes asset partially offset by a $24.5 million increase in cash and cash equivalents. The increase in accrued expenses was primarily due to a $3.0 million increase in accrued drilling costs related to the current development drilling program and a $2.8 million increase in accrued interest expense.

Capital Expenditures

     During the first nine months of 2004, we spent approximately $17.6 million, including exploratory dry hole expense, on our drilling activities and other capital expenditures related to continuing operations. In the first nine months of 2004, we drilled 71 gross (67.4 net) development wells, all of which were successfully completed as producers in the target formation and 3 gross (1.8 net) shallow exploratory wells, which were dry holes. These results exclude approximately $500,000 related to three shallow exploratory wells in progress as of September 30, 2004. If these wells are determined to be dry holes, the cost will be charged to exploratory dry hole expense in subsequent periods.

     We currently expect to spend approximately $24.3 million during 2004 on our drilling activities and other capital expenditures related to continuing operations. We intend to finance our planned capital expenditures through our available cash flow, available revolving credit line and the sale of non-strategic assets. At September 30, 2004, we had cash of $25.9 million and approximately $15.0 million available under the revolving credit facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties.

Capital C Merger

     As disclosed in Note 1 “Merger” to the consolidated financial statements, on July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”), and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C’s general partner is Capital C Energy, LLC, an entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and Peter R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power Fund II, L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered in Houston, Texas. The Merger was completed on July 7, 2004 and for financial reporting purposes will be accounted for as a purchase effective July 1, 2004. The acquisition will result in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date.

     In the Merger, each issued and outstanding share of the Company common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under the Company’s prior credit facility were repaid. In connection with the Consent Solicitation and Tender Offer previously announced by the Company, over 98% of the Company’s $225 million aggregate principal amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the closing of the Merger. As of September 30, 2004, all of the $225 million aggregate principal amount has been paid.

     Capital C obtained the funds necessary to consummate the Merger through (1) equity capital contributions of $77.5 million by its partners, (2) the Company’s entry into a secured credit facility with various lenders arranged through Goldman Sachs Credit Partners, L.P. with a $100 million term facility maturing on July 7, 2011, a $30 million revolving facility maturing on July 7, 2010 and a $40 million letter of credit facility, which amounts are secured by substantially all of the assets of the Company and are guaranteed by two of the Company’s subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas Company (the “Senior Facilities”), and (3) a private placement of $192.5 million aggregate principal amount of 8.75% Senior Secured Notes due 2012 of the Company (the “Notes”), which are secured by a

20

second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities. Pre-existing commodity hedges and ten-year commodity hedges effected in connection with the Merger will also be secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes.

     In connection with the Merger the Company entered into commodity hedges on a substantial portion of its future oil and gas production through the year 2013. See Note 8.

     Our management team remained after the Merger with the exception of the retirement of the former Chief Executive Officer, John L. Schwager. Frost W. Cochran is the Company’s new President and Chief Executive Officer. In addition, B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice Presidents. Upon consummation of the Merger all former directors of the Company resigned and the new Board of Directors consisted of six members, each of whom is elected annually to serve one-year terms. The initial six members of the Board of Directors were Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard. On November 1, 2004, James A. Winne III and Michael Becci were elected to our Board of Directors and were also named Senior Vice Presidents of the Company. Their election brings the Board’s membership to eight.

Financing and Credit Facilities

     At September 30, 2004, we had a $170 million credit facility comprised of: a seven year $100 million term facility; a six year $30 million revolving facility for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a six year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. At September 30, 2004, the interest rate under our base rate option was 6.50%. Under our three month LIBOR option the rate was 4.48%. At September 30, 2004, we had $55 million of outstanding letters of credit. At September 30, 2004, there was no outstanding balance under the revolving credit agreement. Under the term facility the outstanding balance was $99.75 million. We had $15 million of borrowing capacity under our revolving credit facility available for general corporate purposes. As of September 30, 2004, we had satisfied all financial covenants and requirements under the existing credit facilities.

     From time to time we may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. There were no interest rate swaps in the first nine months of 2004 or 2003.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Among other risks, we are exposed to interest rate and commodity price risks.

     The interest rate risk relates to existing debt under the term and revolving credit facilities. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the floating rate exposure is exchanged for a fixed interest rate. A portion of the long-term debt consists of senior secured notes where the interest component is fixed. We had no derivative financial instruments for managing interest rate risks in place as of September 30, 2004 or 2003. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the third quarter would be approximately $254,000. This sensitivity analysis is based on our financial structure at September 30, 2004.

     The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed by the Company. Our financial results can be significantly impacted as commodity prices

21

fluctuate widely in response to changing market forces. From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. We employ a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.50 per Mcf, our gas sales revenues for the quarter would decrease by $620,000, after considering the effects of the hedging contracts in place. At September 30, 2004, we had hedges on a portion of our oil production for the remainder of 2004 through 2013. We had no hedges on oil production during 2003. If the price of crude oil decreased $3.00 per Bbl, oil sales revenues for the quarter would decrease by $58,000. We had net pretax losses on our hedging activities of $13.2 million in the first nine months of 2004 and $9.7 million in the first nine months of 2003.

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed price contract and financial hedging positions by entering into new transactions.

22

     The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at October 31, 2004:

⁽¹⁾ The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00. The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90.

     The proximity of our properties in the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the prices of NYMEX futures contracts for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in our market areas are typically 15 to 60 cents higher per Mcf than comparable NYMEX prices. Our average price received for crude oil is typically $2.50 to $3.25 per barrel below the NYMEX price per barrel.

ITEM 4. CONTROLS AND PROCEDURES

     As of the end of the period covered by this quarterly report, we carried out an evaluation, 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 Exchange Act Rule 13a-15. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective

23

as of the end of the period covered by this quarterly report. During the quarter ended September 30, 2004, there have been no changes in our internal controls over financial reporting, identified in connection with our evaluation thereof that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II Other Information

     Item 6. Exhibits:

     (a) Exhibits

* Filed herewith

24

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

25