Belden & Blake Corporation


	•	The terms of the New Notes are identical to the terms of the Outstanding Notes, except that the New Notes are registered under the Securities Act of 1933 and will not contain restrictions on transfer, registration rights or provisions for additional interest.

	•	The New Notes, like the Outstanding Notes, will not be listed on any securities exchange.


	•	We are offering to exchange up to $192,500,000 of our outstanding 8.75% Senior Secured Notes due 2012 for New Notes with materially identical terms that have been registered under the Securities Act of 1933 and will be generally freely tradable.

	•	We will exchange all Outstanding Notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of New Notes.

	•	The exchange offer expires at 5:00 p.m., New York city time, on January 31, 2005, unless extended.

	•	Tenders of Outstanding Notes may be withdrawn at any time prior to the expiration of the exchange offer.

	•	The exchange of New Notes for Outstanding Notes will not be a taxable event for U.S. federal income tax purposes.

YOU SHOULD CAREFULLY CONSIDER THE RISK FACTORS BEGINNING ON PAGE 15 OF THIS PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE NEW NOTES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, which we refer to as the “SEC.” In making your investment decision, you should rely only upon the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized any other person to provide you with different information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume the information contained in this prospectus is accurate as of any date other than its respective date.

The information is 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 regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. See “Risk Factors” beginning on page 15 of this prospectus.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary may not contain all of the information that you should consider with respect to the New Notes. To understand all of the terms of the New Notes and this exchange offer and for a more complete understanding of our business, you should carefully read this entire prospectus, particularly the section entitled “Risk Factors” beginning on page 15 and the Consolidated Financial Statements and the notes related thereto. 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. The term “you” refers to a prospective investor. The term “Notes” includes both the Outstanding Notes and the New Notes. We have included oil and natural gas terms that are important to an understanding of our business in the section entitled “Glossary of Oil and Natural Gas Terms.”

BELDEN & BLAKE CORPORATION

We are a privately held company formed on June 14, 1991 and are wholly owned by Capital C Energy Operations, LP (“Capital C”). Capital C recently acquired us pursuant to an Agreement and Plan of Merger. The merger was completed on July 7, 2004. Capital C is a controlled affiliate of Carlyle/ Riverstone Global Energy and Power Fund II, L.P. (“Carlyle/ Riverstone”).

We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the Michigan Basin. We are currently one of the largest oil and gas production companies operating in the Appalachian Basin in terms of reserves, acreage held and wells operated. We also have undeveloped acreage in northern Indiana and western Kentucky.

At December 31, 2003, our total estimated proved reserves related to continuing operations were 355 Bcfe. Natural gas comprised approximately 90% of our estimated proved reserves, and 66% of our estimated proved reserves were classified as proved developed. Substantially all of our estimated proved reserves are located in shallow, highly developed, blanket formations with long-lived, stable production profiles. At December 31, 2003, our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coal bed methane properties accounted for 38% and 10%, respectively.

We have begun the process of gathering and evaluating information relating to our proved reserves estimate as of December 31, 2004. Based on this preliminary evaluation, we believe that the December 31, 2004 proved reserves estimate is likely to be less than the December 31, 2003 proved reserves estimate included in our 2003 Form 10-K.

During 2004, our drilling focused on proved undeveloped locations. We expect to report that a substantial portion of this drilling did not add new proved reserves, but rather, converted proved undeveloped reserves into proved developed reserves. As a result of this drilling, coupled with our production in 2004, we expect our total proved reserves to decrease by approximately 18 Bcfe. We believe this decrease will be primarily in the proved undeveloped reserves category.

In addition, based on our preliminary evaluation, we believe that it is reasonably possible that the December 31, 2004 proved reserves estimate could reflect a further decrease of 25 to 50 Bcfe from the December 31, 2003 proved reserves estimate. We believe this reduction also will be primarily in the proved undeveloped reserves category. This decrease is expected to result from several factors including, but not limited to, the following:

— recent production and drilling results;

— reevaluation of our inventory of proved undeveloped well sites; and

— reevaluation of our estimated future development, completion and operating costs

Our evaluation is based on the preliminary information we have available. The reserves estimates at December 31, 2004 could be significantly different than the estimates provided above. The results of our evaluation could change after taking into account the impact of additional information we will gather subsequent to our preliminary review, the effect of the changes in prices for oil and natural gas which have occurred during the year, and other factors that will be considered in preparing the reserves estimates.

We expect to review this information with Wright & Company, Inc., independent petroleum consultants, in conjunction with the preparation of the reserves estimate as of December 31, 2004.

In the third quarter of 2004, we achieved average net production from continuing operations of approximately 47.3 Mmcfe per day from 4,084 gross (3,165 net) (at quarter end) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan. Based on our 2003 year end estimated proved reserves and third quarter 2004 average daily production, our properties have a reserve life of approximately 20 years.

At December 31, 2003, we operated approximately 3,400 wells, or 82% of our gross wells, representing approximately 98% of the value of our estimated proved developed reserves on a PV-10 basis. We believe that operational control of our properties, coupled with ownership of selected gathering assets, enables us to better manage our operating costs and capital expenditures and execute our field development plans. At December 31, 2003, we held leases on 1,118,512 gross (924,033 net) acres, including 477,434 gross (355,826 net) undeveloped acres. The acreage numbers include the Trenton Black River (“TBR”) properties that were sold in June 2004.

We own and operate approximately 1,260 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets, including those in the northeastern United States. 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 New York Mercantile Exchange (“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.

In connection with our plan to refocus our operations and capital budget on developing lower cost, lower risk reserves and enhancing existing production, we sold all of our TBR oil and natural gas operations. Operations on our TBR properties targeted deeper, less developed formations, and therefore were riskier and more speculative, than the rest of our drilling program. We also sold Arrow Oilfield Services, our oilfield services division (“Arrow”). Both of these transactions were classified as discontinued operations. Historical information has been restated to remove the TBR properties and Arrow from continuing operations. See “Recent Developments — The Dispositions.”

We maintain our corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720 and our telephone number at that location is (330) 499-1660.

Business Strategy

The key elements of our business strategy are as follows:

Focus on Exploiting and Developing Lower Cost, Lower Risk Reserves. We intend to focus our personnel and capital budget primarily on exploitation and development of our acreage in shallow, highly developed, blanket formations. Historically, our drilling completion rates and those of others drilling in these formations have exceeded 90%. We believe that this approach will substantially reduce many of the risks normally associated with oil and gas exploitation and development activities. We estimate that we have over 1,000 low-risk drilling locations across our properties, the majority of which are classified as proved undeveloped locations. In the second half of 2004, we plan to drill 59 low-risk development wells, representing approximately 95% of our remaining drilling budget.

Employ Long-Term, Fixed-Price Hedges to Protect Margins. We expect to manage commodity price risk by hedging substantial quantities of our expected production. We believe this approach has enhanced the predictability of our operating cash flow. To this end, we have become a party to a long-term hedging program with J. Aron & Company (“J. Aron”), an affiliate of Goldman, Sachs & Co. We anticipate that the hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves, and will range from 52% to 84% of such expected production in any year. In addition, we may enter into additional hedging transactions with respect to reserves we add in the future. See “Description of Other Indebtedness — Post-Merger Debt — The Hedges.”

Realize Efficiencies in Unit Operating Costs. We strive to control our unit operating costs and improve our profit margins on production from existing and acquired properties through the application of advanced production technologies, operating efficiencies and mechanical improvements. We continually review our properties to determine what actions we can take to reduce operating costs and/or improve production. We strive to control field level costs through improved operating practices such as computerized production scheduling and the use of hand-held computers to gather field data. Actions that may be taken to improve production include modifying surface facilities, redesigning downhole equipment and recompleting existing wells. These actions can result in increased operating costs.

Evaluate Potential Opportunistic Acquisitions. We may seek to opportunistically acquire properties in the Appalachian and Michigan Basins that complement our strategy and operations and provide additional exploitation and development opportunities.

RECENT DEVELOPMENTS

The Merger

Pursuant to an Agreement and Plan of Merger with Capital C, dated as of June 15, 2004 (the “Merger Agreement”), a wholly owned subsidiary of Capital C merged with and into us (the “Merger”) and we were the surviving corporation. The Merger was completed on July 7, 2004.

Capital C is a privately held partnership owned by Capital C Energy Partners, L.P. and affiliates of Carlyle/ Riverstone. Capital C Energy Partners, L.P. is a privately owned partnership formed in 2002 to accumulate and manage a portfolio of onshore U.S. oil and gas properties. Capital C’s principal executive offices are located at 333 Clay Street, Suite 4960, Houston, Texas 77002 and its main telephone number is (713) 571-9393.

The Senior Facilities

We recently entered into a new Senior Credit Agreement providing for a $100 million term facility, a $30 million revolving facility (including letters of credit) and a $40 million letter of credit facility (collectively, the “Senior Facilities”). Indebtedness under the Senior Facilities constitutes our senior secured indebtedness and is secured by a first-priority lien on a substantial majority of the aggregate value of our proved producing reserves on a PV-10 basis and is guaranteed by our subsidiaries on a first-priority senior secured basis. The Notes constitute our senior secured indebtedness and are secured by a second-priority lien on the same assets and are guaranteed by the same subsidiaries on a second-priority senior secured basis. See “Description of Other Indebtedness” and “Description of the Collateral.”

The Hedges

At the effective time of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and, as required by the Senior Facilities and the indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor or permitted assigns. We anticipate that the Hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves and will range from 52% to 84% of such expected production in any

year. The Hedges primarily take the form of monthly settled fixed-price swaps in respect of the settlement prices for the market standard NYMEX futures contracts on natural gas and crude oil. We will pay a NYMEX-based floating price per Mmbtu, in the case of Hedges on natural gas, and will pay a NYMEX-based floating price per Bbl, in the case of Hedges on crude oil, for each month during the term of the Hedges and will receive a fixed price per Mmbtu or Bbl (as the case may be) in accordance with a monthly schedule of fixed prices. We may enter into natural gas and crude oil hedges with third parties other than J. Aron.

The letter of credit facility provides up to $40 million of credit support for our obligations under the Hedge Agreement and other hedging transactions. Our obligations under the Hedge Agreement are also secured by up to $15 million of letters of credit under the revolving facility. To the extent our obligations exceed such letters of credit, such obligations under the Hedge Agreement and other hedging transactions will be secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes and are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes on a second-priority senior secured basis. See “Description of Other Indebtedness — Post-Merger Debt — The Hedges.”

The Dispositions


	*Sale of Arrow Assets*

We sold the Michigan assets of Arrow in May 2004. We sold the Ohio and Pennsylvania-related assets of Arrow in June 2004. These transactions were classified as discontinued operations. Historical information has been restated to remove Arrow from continuing operations.


	*Sale of Trenton Black River Assets*

On June 25, 2004, we completed the sale of our interests, or rights to our interests, in the TBR assets in accordance with a letter agreement dated June 14, 2004 (the “TBR Letter Agreement”) with a third party. This transaction was classified as discontinued operations. Historical information has been restated to remove the TBR properties from continuing operations.

THE EXCHANGE OFFER


Exchange Offer		We are offering to exchange New Notes for Outstanding Notes.

Expiration Date		The exchange offer will expire at 5:00 p.m. New York City time, on January 31, 2005, unless we decide to extend it.

Condition to the Exchange Offer		The exchange and registration rights agreement does not require us to accept Outstanding Notes for exchange if the exchange offer or the making of any exchange by a holder of the Outstanding Notes would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of Outstanding Notes being tendered. See “The Exchange Offer — Conditions to the Exchange Offer.”

Procedures for Tendering Outstanding Notes		To participate in the exchange offer, you must complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal, and transmit it together with all other documents required by the letter of transmittal, including the Outstanding Notes that you wish to exchange, to BNY Midwest Trust Company, as exchange agent, at the address indicated on the cover page of the letter of transmittal. In the alternative, you can tender your Outstanding Notes by following the procedures for book-entry transfer described in this prospectus.

		If your Outstanding Notes are held through The Depository Trust Company and you wish to participate in the exchange offer, you may do so through the automated tender offer program of The Depository Trust Company. If you tender under this program, you will agree to be bound by the letter of transmittal that we are providing with this prospectus as though you had signed the letter of transmittal.

		If a broker, dealer, commercial bank, trust company or other nominee is the registered holder of your Outstanding Notes, we urge you to contact that person promptly to tender your Outstanding Notes in the exchange offer.

		For more information on tendering your Outstanding Notes, please refer to the sections in this prospectus entitled “The Exchange Offer — Terms of the Exchange Offer,” “— Procedures for Tendering, and “— Book-Entry Transfer.”

Guaranteed Delivery Procedures		If you wish to tender your Outstanding Notes and you cannot submit your required documents to the exchange agent on time, you may tender your Outstanding Notes according to the guaranteed delivery procedures described in “The Exchange Offer — Guaranteed Delivery Procedures.”

Withdrawal of Tenders		You may withdraw your tender of Outstanding Notes at any time prior to the expiration date. To withdraw, you must have delivered a written or facsimile transmission notice of withdrawal to the exchange agent at its address indicated on the cover page of the letter of transmittal before 5:00 p.m. New York City time


		on the expiration date of the exchange offer. See “The Exchange Offer — Withdrawal of Tenders.”

Acceptance of Outstanding Notes and Delivery of New Notes		If you fulfill all conditions required for proper acceptance of Outstanding Notes, we will accept any and all Outstanding Notes that you properly tender in the exchange offer on or before 5:00 p.m. New York City time on the expiration date. We will return any Outstanding Notes that we do not accept for exchange to you without expense as promptly as practicable after the expiration date and acceptance of the Outstanding Notes for exchange. We will also deliver the New Notes as promptly as practicable after the expiration date. Please refer to the section in this prospectus entitled “The Exchange Offer — Terms of the Exchange Offer.”

Fees and Expenses		We will bear all expenses related to the exchange offer. Please refer to the section in this prospectus entitled “The Exchange Offer — Fees and Expenses.”

Use of Proceeds		The issuance of the New Notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our exchange and registration rights agreement.

Consequences of Failure to Exchange Outstanding Notes		If you do not exchange your Outstanding Notes in this exchange offer, you will no longer be able to require us to register the Outstanding Notes under the Securities Act of 1933 except in the limited circumstances provided under our exchange and registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the Outstanding Notes unless we have registered the Outstanding Notes under the Securities Act of 1933, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act of 1933.

U.S. Federal Income Tax Considerations		The exchange of New Notes for Outstanding Notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Certain United States Federal Income Tax Considerations.”

Exchange Agent		We have appointed BNY Midwest Trust Company as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus or the letter of transmittal and requests for the notice of guaranteed delivery to the exchange agent addressed as follows: Bank of New York, Corporate Trust Department, Reorganization Unit, 101 Barclay Street — 7 East, New York, New York 10286. Eligible institutions may make requests by facsimile at (212) 298-1915.

TERMS OF THE NEW NOTES

The New Notes will be identical to the Outstanding Notes except that the New Notes are registered under the Securities Act of 1933 and will not have restrictions on transfer, registration rights or provisions for additional interest. The New Notes will evidence the same debt as the Outstanding Notes, and the same indenture will govern the New Notes and the Outstanding Notes.

The following summary contains basic information about the New Notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the New Notes, please refer to the section of this document entitled “Description of the Notes.”


Issuer		Belden & Blake Corporation.

Notes Offered		8.75% Senior Secured Notes due 2012.

Maturity Date		July 15, 2012.

Interest Payment Dates		Interest will accrue on the New Notes from the date of issuance and will be payable semi-annually, on each January 15 and July 15, commencing January 15, 2005.

Guarantees		The New Notes will be jointly and severally guaranteed on a senior basis by our existing and future domestic subsidiaries (other than Immaterial Subsidiaries).

Security		The New Notes will be secured by second-priority liens, subject to certain exceptions and permitted liens, on the same assets that will secure the first-priority liens and the Hedges, including:

		• certain of our and the subsidiary guarantors’ existing and after-acquired real, personal, tangible and intangible property, and

		• all of our capital stock and the capital stock of existing and future domestic subsidiaries owned directly by us or the subsidiary guarantors. See “Description of the Collateral.”

Ranking		The New Notes will be our second-priority senior secured obligations and will rank:

		• senior in right of payment to any of our future debt that expressly provides that it is subordinated to the New Notes;

		• effectively senior in right of payment to any of our existing and future debt that is not secured to the extent of the value of the assets securing the New Notes (subject to first-priority liens);

		• equal in right of payment with the obligations under the Hedges, and with any future senior unsecured debt that does not expressly provide that it is subordinated to the New Notes or any future second-priority senior secured debt;

		• effectively subordinated to all of our first-priority senior secured debt (including the new Senior Facilities) to the extent of the value of the assets securing such debt; and

		• structurally subordinated to all indebtedness and other liabilities (including trade payables and lease obligations) of any of our subsidiaries which are not guarantors.


		As of September 30, 2004, after giving effect to the issuance of the Outstanding Notes and the incurrence of the new Senior Facilities and the Hedges and our use of the net proceeds therefrom, as described in “Use of Proceeds,” the Outstanding Notes would have been junior to approximately $155 million of first-priority senior secured debt under the Senior Facilities. These obligations include the $55 million aggregate amount of letters of credit issued under the Senior Facilities. After giving effect to the application of the net proceeds from the issuance of the Outstanding Notes, we also would have been able to incur in the future $15 million of additional indebtedness under our first-priority secured revolving credit facility.

Sinking Fund		None.

Optional Redemption		At any time prior to July 15, 2007, we may redeem up to 35% of the aggregate original principal amount of the New Notes, using the net proceeds of specified equity offerings, at a redemption price equal to 108.750% of the principal amount of the New Notes, plus accrued and unpaid interest to the date of redemption. In addition, at any time prior to July 15, 2008, we may redeem the New Notes, in whole or in part, at a price equal to 100% of the principal amount of the New Notes plus the “make-whole” premium described in “Description of the Notes — Optional Redemption.” On or after July 15, 2008, we may redeem all or a portion of the New Notes at the redemption prices listed in “Description of the Notes — Optional Redemption,” plus accrued and unpaid interest to the date of redemption.

Change of Control		If we experience specific kinds of changes of control, we would be required to offer to purchase each holder’s New Notes, in whole or in part, at a price equal to 101% of the principal amount plus accrued and unpaid interest to the date of purchase.

Certain Covenants		Covenants contained in the indenture under which the New Notes will be issued will, among other things, limit our ability and the ability of our restricted subsidiaries to:

		• incur additional indebtedness;

		• pay dividends or make other distributions on stock, redeem stock or redeem subordinated obligations;

		• make investments;

		• create liens on assets;

		• sell assets;

		• enter into agreements that restrict the ability of subsidiaries to pay dividends or make other payments to us or our restricted subsidiaries;

		• merge or consolidate;

		• terminate the Hedge Agreement; and

		• enter into transactions with affiliates.


		All of these covenants are subject to important exceptions and qualifications that are described under “Description of the Notes.”

		If the New Notes receive investment grade ratings from both Standard & Poor’s Rating Services and Moody’s Investor Services, Inc. and no default or event of default under the New Notes has occurred and is continuing, many of these covenants will be suspended.

Transfer Restrictions; Absence of a Public Market for the New Notes		The New Notes generally will be freely transferable, but will be new securities for which there is currently no market. There can be no assurance as to the development or liquidity of any market for the New Notes. We do not intend to apply for listing of the New Notes on any securities exchange or for the quotation of the New Notes in any automated dialer quotation system.

Risk Factors		For a discussion of certain risks that should be considered in connection with an investment in the New Notes, see “Risk Factors” beginning on page 15 of this prospectus.

SUMMARY HISTORICAL CONSOLIDATED FINANCIAL DATA

The summary historical consolidated financial data set forth below is derived from our consolidated financial statements. The summary historical consolidated financial data as of and for each of the years ended December 31, 1999, 2000, 2001, 2002 and 2003 have been derived from our audited Consolidated Financial Statements. The summary historical consolidated financial data as of and for the nine months ended September 30, 2003 and the successor company 91 day period from July 2, 2004 to September 30, 2004 and the predecessor company for the 183 day period from January 1, 2004 have been derived from our unaudited consolidated financial statements, which were prepared on the same basis as our audited consolidated financial statements and, in the opinion of management, include all adjustments considered necessary for a fair presentation of our financial position and results of operations for such periods. The results from any interim period are not necessarily indicative of the results that may be expected for a full fiscal year. Historical results are not necessarily indicative of the results to be expected in the future. The data presented below should be read together with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related notes thereto.


																		Successor
		Predecessor Company																Company

															For the 183 Day			For the 91 Day
													Nine months		Period from			Period from
		Year ended December 31,											ended		January 1, 2004			July 2, 2004 to
													September 30,		to July 1,			September 30,
		1999		2000		2001		2002		2003			2003		2004			2004

																		(unaudited,
		(in thousands)											(unaudited, in thousands)					in thousands)
STATEMENT OF OPERATIONS DATA
	Revenues:
	Oil and gas sales	$	74,926	$	73,813	$	89,491	$	90,462	$	84,610		$	62,204	$	45,307		$	21,668
	Gas gathering and marketing		46,807		22,178		19,488		13,526		10,538			7,934		5,057			2,179
	Other		4,703		3,079		1,753		1,557		266			332		458			550

	Total revenues		126,436		99,070		110,732		105,545		95,414			70,470		50,822			24,397
	Expenses:
	Production expense		20,566		19,264		21,214		20,247		20,017			14,302		10,951			5,500
	Production taxes		3,171		2,340		2,298		1,789		2,449			1,944		1,300			650
	Gas gathering and marketing		42,836		19,658		16,210		11,000		9,570			7,398		4,533			2,026
	Exploration expense		6,271		5,385		5,916		8,834		6,849			4,690		2,717			1,334
	General and administrative expense		5,412		4,617		4,395		4,557		4,559			3,369		2,500			1,100
	Franchise, property and other taxes		473		309		148		11		202			170		115			67
	Depreciation, depletion and amortization		38,973		25,576		25,132		21,339		18,098			12,566		9,089			8,611
	Impairment of oil and gas properties		—		—		1,398		—		896			—		—			—
	Accretion expense		—		—		—		—		343			247		195			134
	Derivative fair value (gain) loss		—		—		—		—		(319	)		166		2,038			3,788
	Severance and other nonrecurring expense		2,778		241		1,954		923		—			—		—			—
	Transaction-related expenses		—		—		—		—		—			—		21,155			—

	Total expenses		120,480		77,390		78,665		68,700		62,664			44,852		54,593			23,210

	Operating income (loss)		5,956		21,680		32,067		36,845		32,750			25,618		(3,771	)		1,187


																								Successor
			Predecessor Company																					Company

																					For the 183 Day			For the 91 Day
																		Nine months			Period from			Period from
			Year ended December 31,															ended			January 1, 2004			July 2, 2004 to
																		September 30,			to July 1,			September 30,
			1999			2000			2001			2002			2003			2003			2004			2004

																								(unaudited,
			(in thousands)															(unaudited, in thousands)						in thousands)
	Other expense (income):
	Loss (gain) on sale of subsidiaries and other income			1,521			(15,064	)		—			154			—			—			—			—
	Loss on early extinguishment on debt			—			2,140			—			—			—			—			—			—
	Interest expense			31,991			27,288			25,055			22,506			23,580			17,663			12,184			6,143

				33,512			14,364			25,055			22,660			23,580			17,663			12,184			6,143

	(Loss) income from continuing operations before income taxes and cumulative effect of change in accounting principle			(27,576	)		7,316			7,012			14,185			9,170			7,955			(15,955	)		(4,956	)
	(Benefit) provision for income taxes			(10,505	)		2,475			(188	)		5,250			3,210			2,844			(3,318	)		(2,314	)

	(Loss) income from continuing operations before cumulative effect of change in accounting principle			(17,051	)		4,841			7,200			8,935			5,960			5,111			(12,637	)		(2,642	)
	(Loss) income from discontinued operations, net of tax			(1,252	)		(1,880	)		(733	)		(6,470	)		(10,681	)		(4,769	)		27,840			338

	(Loss) income before cumulative effect of change in accounting principle			(18,303	)		2,961			6,467			2,465			(4,721	)		342			15,203			(2,304	)
	Cumulative effect of change in accounting principle, net of tax			—			—			—			—			2,397			2,397			—			—

	Net (loss) income		$	(18,303	)	$	2,961		$	6,467		$	2,465		$	(2,324	)	$	2,739		$	15,203		$	(2,304	)

STATEMENT OF CASH FLOWS DATA
	Net cash provided by (used in) continuing:
		Operating activities	$	10,327		$	27,596		$	44,483		$	50,275		$	26,235		$	20,703		$	18,594		$	14,260
		Investing activities		3,925			46,333			(38,393	)		(16,297	)		(31,322	)		(14,395	)		(12,480	)		(7,392	)
		Financing activities		(32,345	)		(73,276	)		(3,691	)		(33,419	)		20,235			12,115			(48,569	)		(1,290	)
BALANCE SHEET DATA (AT END OF PERIOD)
	Cash and cash equivalents			4,369			1,779			1,925			1,715			1,428			983						25,949
	Net property and equipment			279,046			221,063			229,243			218,645			230,442			232,745						514,992
	Total assets			350,695			285,117			305,349			263,845			285,311			290,775						573,753
	Total long-term liabilities			303,731			286,858			284,745			251,959			276,611			268,879						299,006
	Total shareholders’ (deficit) equity			(51,590	)		(48,313	)		(27,279	)		(44,645	)		(57,340	)		(47,884	)					52,473

SUMMARY OPERATING DATA

The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the periods indicated, excluding discontinued operations. However, it does not exclude dispositions of properties that did not qualify as discontinued operations. See Note 4 to the Consolidated Financial Statements:



												Nine months ended
		Year ended December 31,										September 30,

		1999		2000		2001		2002		2003		2003		2004


												(unaudited)
Production:
	Natural gas (Mmcf)		25,285		18,525		17,164		15,882		14,834		10,857		11,492
	Oil (Mbbl)		710		590		644		522		413		306		282
	Natural gas equivalents (Mmcfe)		29,548		22,064		21,030		19,012		17,311		12,694		13,183
Average price(1):
	Natural gas (per Mcf)	$	2.50	$	3.12	$	4.35	$	4.95	$	4.92	$	4.94	$	5.00
	Oil (per Bbl)		16.57		27.29		23.04		22.72		28.06		28.07		33.73
	Natural gas equivalents (per Mcfe)		2.54		3.35		4.26		4.76		4.89		4.90		5.08
Average costs (per Mcfe):
	Production expense		0.70		0.87		1.01		1.07		1.16		1.13		1.25
	Production taxes		0.11		0.11		0.11		0.09		0.14		0.15		0.15
	Depletion		0.92		0.77		0.91		0.87		0.85		0.79		1.16
Operating margin (per Mcfe)(2)			1.73		2.37		3.14		3.60		3.59		3.62		3.68

(1) Average prices reflect the effect of hedges in effect during the periods indicated.

(2) Operating margin (per Mcfe) is defined as average price less production expense and production taxes.

SUMMARY RESERVE DATA

The reserve and present value estimates as of December 31, 2001, 2002 and 2003 for our properties were prepared by Wright & Company, Inc., independent petroleum engineers. The reserve estimates were prepared in accordance with guidelines established by the SEC regarding the present value of future reserves and future net revenues. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. Please read “Risk Factors — Information concerning our reserves and future net revenues is uncertain” and Note 16 to the Consolidated Financial Statements included elsewhere in this prospectus.



		As of December 31,

		2001			2002			2003

ESTIMATED PROVED RESERVES:(3)
	Appalachian Basin-Conventional (Bcfe)(1)		202.1			197.8			189.9
	Michigan Basin (Bcfe)		120.8			137.3			133.5
	Appalachian Basin-Coal Bed Methane (Bcfe)		44.8			39.9			36.4

	Total oil and natural gas (Bcfe)		367.7			375.0			359.8
	Percent proved developed		67	%		62	%		65	%
	Percent natural gas		91	%		89	%		90	%
	PV-10 (in thousands)(2)	$	224,987		$	479,586		$	596,952

(1) The TBR properties accounted for approximately 5 Bcfe of estimated proved reserves as of December 31, 2003. We did not have proved reserves attributable to these properties prior to 2003. We sold our interests, or rights to our interests, in these properties in June 2004.

(2) The weighted average year-end prices used for purposes of estimating our proved reserves and future net revenues were $6.19 per Mcf of natural gas and $29.78 per barrel of oil at December 31, 2003, $4.99 per Mcf of natural gas and $27.81 per barrel of oil at December 31, 2002, and $2.92 per Mcf of natural gas and $17.85 per barrel of oil at December 31, 2001. These prices did not include the anticipated effect of our hedging financial instruments.

(3) Please read the discussion on Page 1 relating to our December 31, 2004 proved reserves estimate.

ACREAGE DATA

The following table summarizes our developed and undeveloped acreage with respect to our properties as of the dates indicated. These numbers include acreage associated with the TBR properties that were sold in June 2004.



				As of December 31,

				2001		2002		2003

ACREAGE:
	Gross acres:
		Developed			450,605		458,906		641,078
		Undeveloped			734,933		919,024		477,434

			Total		1,185,538		1,377,930		1,118,512
	Net acres:
		Developed			409,712		415,711		568,207
		Undeveloped			643,574		772,164		355,826

			Total		1,053,286		1,187,875		924,033

SUMMARY UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA

The following tables set forth summary unaudited pro forma financial and operating data which give effect to the Merger, the issuance of the Outstanding Notes and the incurrence of indebtedness under the Senior Facilities to refinance our existing indebtedness (collectively, the “Transactions”). The summary unaudited pro forma statement of operations data assume that the Transactions occurred on January 1, 2003. The summary unaudited pro forma balance sheet data assume that the Transactions occurred on July 1, 2004. The summary unaudited pro forma financial and operating data do not purport to be indicative of the results of operations or the financial position that would have occurred had the Transactions occurred on the dates indicated, nor do they purport to be indicative of future results of operations or financial position. The summary unaudited pro forma financial and operating data should be read in conjunction with our historical consolidated financial statements, our unaudited consolidated pro forma financial statements and related notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial and operating information contained in this prospectus.



							Nine months ended
				Year ended			September 30,
				December 31,
				2003			2003			2004


				(in thousands)
Statement of Operations Data
	Revenues:
		Oil and gas sales		$	84,610		$	62,204		$	66,975
		Gas gathering and marketing			10,538			7,934			7,236
		Other			266			332			1,008

					95,414			70,470			75,219
	Expenses:
		Production expense			20,017			14,302			16,451
		Production taxes			2,449			1,944			1,950
		Gas gathering and marketing			9,570			7,398			6,559
		Exploration expense			6,849			4,690			4,051
		General and administrative expense			4,559			3,369			3,600
		Franchise, property and other taxes			202			170			182
		Depreciation, depletion and amortization			25,929			25,490			26,163
		Impairment of oil and gas properties			896
		Accretion expense			543			397			479
		Derivative fair value (gain) loss			(319	)		166			5,826

			Total expenses		70,695			57,926			65,261

	Operating income				24,719			12,544			9,958
	Other expense:
		Interest expense			22,589			16,934			16,903

	Income (loss) from continuing operations before income taxes				2,130			(4,390	)		(6,945	)
		Provision (benefit) for income taxes			605			(1,569	)		(3,153	)

		Income (loss) from continuing operations		$	1,525		$	(2,821	)	$	(3,792	)


		As of
		September 30,
		2004

Balance Sheet Data
	Cash and cash equivalents	$	25,949
	Net property and equipment		514,992
	Total assets		573,753
	Total indebtedness		292,349
	Total shareholders’ equity		52,473

An investment in the New Notes involves significant risks. You should consider carefully all of the information that we have included in this prospectus. In particular, you should consider carefully the risk factors described below before deciding whether to invest in the New Notes.

To manage our exposure to price risks in the marketing of our oil and natural gas, we enter into natural gas fixed-price physical delivery contracts as well as commodity price swap and collar contracts from time to time with respect to a portion of our current and future production. In connection with the Merger, we became a party to a long-term hedging program with J. Aron. We anticipate the Hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves. These transactions may limit our potential gains if oil and/or natural gas prices were to rise substantially over the fixed prices specified in the Hedge Agreement. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:


	•	our production is less than expected;

	•	there is a narrowing of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements;

	•	there is a failure of a hedge counterparty to perform under the Hedge Agreement or other hedge transactions; or

	•	a sudden, unexpected event materially impacts oil and/or natural gas prices.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk.”

If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facilities or otherwise, our ability to execute our development plans, replace our reserves or maintain our production levels could be greatly limited. Our current development plans will require us to make large capital expenditures for the exploitation and development of our natural gas properties. Historically, we have funded our capital expenditures through a combination of funds generated internally from sales of production or properties, the issuance of equity, long-term debt financing and short-term financing arrangements. We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our new Senior Facilities in an amount sufficient to enable us to pay our indebtedness, including the Notes or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new Senior Facilities and the Notes, on commercially reasonable terms or at all. Future cash flows and the availability of financing will be subject to a number of variables, such as:


	•	the success of our projects in the Appalachian and Michigan Basins;

	•	our success in locating and producing new reserves;

	•	the level of production from existing wells; and

	•	prices of oil and natural gas.

In addition, debt financing could lead to a diversion of cash flow to satisfy debt servicing obligations and to restrictions on our operations.

While we have entered into long-term hedges covering most of our production in an effort to mitigate the risk of a decline in prices for oil and gas, a substantial portion of our production will remain unhedged. We expect that the markets for oil and gas will continue to be volatile. Any substantial or extended decline in the price of oil or gas would negatively affect our financial condition and results of operations. Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for oil and gas. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. Substantially all of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in the price of natural gas. Various factors beyond our control can affect prices of natural gas. These factors include: North American supplies of oil and gas; political instability or armed conflict in oil or gas producing regions; the price and level of foreign imports; worldwide economic conditions; marketability of production; the level of consumer demand; the price, availability and acceptance of alternative fuels; the availability of pipeline capacity; weather conditions; and actions of federal, foreign, state, and local authorities.

These external factors and the volatile nature of the energy markets make it difficult to estimate future commodity prices.

There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.

We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise

This prospectus and our Securities and Exchange Commission filings contain estimates of our proved oil and natural gas reserves and the estimated future net revenues from such reserves. Actual results will most likely vary from amounts estimated, and any significant variance could have a material adverse effect on our future results of operations.

Reserve estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

At December 31, 2003, approximately 34% of our estimated proved reserves related to continuing operations were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on analogy to existing wells rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

Analysts and investors should not construe the present value of future net reserves, or PV-10, as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from estimated proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flows, including:


	•	the amount and timing of actual production;

	•	supply and demand for natural gas;

	•	curtailments or increases in consumption by natural gas purchasers; and

	•	changes in governmental regulations or taxation.

The timing of the production of oil and natural gas and of the related expenses affect the timing of actual future net cash flows from estimated proved reserves and, thus, their actual present value. In addition, the 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

Our future drilling activities may not be successful, and we cannot assure you that our overall drilling success rate or our drilling success rate for activity within a particular area will not decline. In addition, the wells that we drill may not recover all or any portion of our capital investment in the wells, infrastructure, or the underlying leaseholds. Unsuccessful drilling activities could negatively affect our results of operations and financial condition. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:


	•	unexpected drilling conditions;

	•	pressure or irregularities in formations;

	•	equipment failures or accidents;

	•	ability to hire and train personnel for drilling and completion services;

	•	adverse weather conditions;

	•	compliance with governmental requirements; and

	•	shortages or delays in the availability of drilling rig services and the delivery of equipment.

In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. There is no guarantee that the potential drilling locations that we have identified will ever produce oil or natural gas.

If our development drilling activities are not successful, we may not be able to replace or grow our reserves.

As part of our growth strategy, we may make additional acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions:


	•	some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;

	•	we may assume liabilities that were not disclosed or that exceed our estimates;

	•	we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

	•	acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

	•	we may incur additional debt related to future acquisitions.

If our acquisition activities are not successful, our ability to replace or grow our reserves may be limited.

We operate in a highly competitive industry. We compete with major oil companies, independent producers and institutional and individual investors, who are actively seeking oil and natural gas properties throughout the world, along with the equipment, labor and materials required to operate properties. Many

The business of exploring for and, to a lesser extent, developing oil and natural gas properties is an activity that involves a high degree of business and financial risk. Property acquisition decisions generally are based on various assumptions and subjective judgments that are speculative. It is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Moreover, the successful completion of an oil or natural gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or marginally economic.

The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us a substantial loss. In addition, we may be held liable for environmental damage caused by previous owners of property that we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for operation, development, production or acquisitions or cause us to incur losses. An event that is not fully covered by insurance (for example losses resulting from pollution and environmental risks, which are not fully insurable) could have a material adverse effect on our financial condition and results of operations.

Federal, state, and local authorities extensively regulate the oil and natural gas industry. Noncompliance with these statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. Regulations affect various aspects of oil and natural gas drilling and production activities, including the pricing and marketing of oil and natural gas production, the drilling of wells (through permit and bonding requirements), the positioning of wells, the unitization or pooling of oil and natural gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. These laws and regulations are under constant review for amendment or expansion.

Our operations are subject to stringent and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities. We could be forced to expend significant resources to comply with new laws or regulations, or changes to current requirements. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between governmental environmental agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation, as well as our efforts to prevent future spills. Moreover, our failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and the issuance of injunctions that restrict or prohibit the performance of operations. See “Business and Properties — Regulation — Environmental Regulations.”

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties, and changes in our contracts with these third parties could materially affect our operations.

In addition, federal, state, and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, and general economic conditions could adversely affect our ability to gather or transport our oil and natural gas. See “Business and Properties — Regulation — Federal Regulation of Sales and Transportation of Natural Gas” and “Business and Properties — Regulation — Federal Regulation of Sales and Transportation of Crude Oil.”

We are a wholly owned subsidiary of Capital C. As a result of this ownership, Capital C is able to direct the election of our Board of Directors and therefore, direct our management and policies. Capital C may unilaterally approve mergers and other fundamental corporate changes involving us, which require shareholder approval. The interests of Capital C as shareholder may differ from the interests of holders of our Notes. See “Certain Relationships and Related Transactions.”

We will only issue New Notes in exchange for Outstanding Notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the Outstanding Notes and you should carefully follow the instructions on how to tender your Outstanding Notes. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of Outstanding Notes.

If you do not exchange your Outstanding Notes for New Notes pursuant to the exchange offer, the Outstanding Notes you hold will continue to be subject to existing transfer restrictions. In general, you may not offer or sell the Outstanding Notes except under and exemption from, or in a transaction not subject to, the Securities Act of 1933 and applicable states securities laws. We do not plan to register the Outstanding Notes under the Securities Act of 1933 unless our exchange and registration rights agreement with the initial purchasers of the Outstanding Notes requires us to do so. Further, if you continue to hold any Outstanding Notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of those Notes outstanding.

After giving effect to the sale of the Outstanding Notes and the borrowing under the Senior Facilities and the application of the net proceeds therefrom and our entry into the Hedge Agreement, we had approximately $348.6 million in outstanding debt and letters of credit issued. We are permitted to incur additional debt, including debt that may share in the first-priority liens on the collateral securing the Senior Facilities, the Hedges, and the Notes, provided we meet certain requirements in the indenture governing the Notes, the Hedge Agreement and the new Senior Facilities. We will also be permitted to incur additional debt that is secured by the collateral on an equal and ratable basis with the Notes if we satisfy a secured leverage ratio test. See “Description of the Notes — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and “Description of the Notes — Certain Covenants — Liens.” Our ability to incur additional debt in the future as either first-priority secured or second-priority secured and, in such event, to enable the holders thereof to share in the collateral on either a priority basis


	•	making it more difficult for us to satisfy our obligations under the Notes or other debt and, if we fail to comply with the requirements of any of our debt, could result in an event of default;

	•	requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

	•	limiting our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;

	•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

	•	detracting from our ability to withstand successfully a downturn in our business or the economy generally; and

	•	placing us at a competitive disadvantage relative to other less leveraged competitors.

In addition, all amounts owing under the revolving and letter of credit components of the new Senior Facilities will become due before any principal payments on the Notes are scheduled to become due and such amounts may need to be refinanced. Furthermore, to the extent that we are unable to repay the principal amount of the Notes at maturity out of cash on hand, we will need to refinance the Notes, or repay the Notes with the proceeds of an equity offering, at or prior to their maturity. There can be no assurance that we will be able to generate sufficient cash flow to service our interest payment obligations under our indebtedness or that future borrowings or equity financing will be available for the payment or refinancing of our indebtedness. To the extent that we are not successful in negotiating renewals of our borrowings or in arranging new financing, we may have to sell significant assets, which would have a material adverse effect on our business and results of operations. Among the factors that will affect our ability to effect an offering of our capital stock or refinance the Notes are financial market conditions and our value and performance at the time of such offering or refinancing. There can be no assurance that any such offering or refinancing can be successfully completed. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” and “Description of Other Indebtedness.”

All of these factors could have a material adverse effect on our business, financial condition, results of operations, prospects and ability to satisfy our obligations under the Notes.

The Notes are secured by second-priority liens, on a parity basis with the liens securing the Hedges, on certain of our assets and the assets of our subsidiary guarantors, subject to certain permitted prior liens. The same assets have also been pledged to secure existing and future first-priority secured debt. To the extent that any of these assets are released from the liens securing the Senior Facilities and the Hedges, these assets will also be released from the liens securing the Notes. The Notes will be effectively subordinated in right of payment to all of our and our subsidiary guarantors’ existing and future first-priority secured debt to the extent of the value of the assets securing that debt.

The holders of the first-priority liens will receive all proceeds from the liquidation of the collateral until all obligations secured by such liens are paid in full. Following payment of the first-priority liens in full, the holders of the second-priority liens will receive all proceeds from the liquidation of the collateral until all obligations secured by such liens are paid in full. The amount to be received from a liquidation of the collateral will depend upon numerous factors including market and economic conditions, the availability of buyers, the timing and manner of sale and similar factors. There can be no assurance that the collateral can or will be liquidated in a short period of time. No independent appraisals of any of the

If the proceeds of any sale of the pledged assets were not sufficient to repay all amounts due on the Notes, the holders of the Notes (to the extent the Notes were not repaid from the proceeds of the sale of the pledged assets) would have only an unsecured claim against our remaining assets. See “Description of the Collateral” and “Description of the Notes — Collateral Trust Agreement.”

In addition, the Notes may not be guaranteed by all of our subsidiaries (other than Immaterial Subsidiaries) in the future, and any non-guarantor subsidiaries are permitted to incur some indebtedness under the terms of the indenture. If a guarantor is released from its guarantee of the Senior Facilities and the Hedges, that guarantor’s guarantee of the Notes will also be released. As a result, holders of the Notes offered hereby will be effectively subordinated to claims of third-party creditors of our non-guarantor subsidiaries. Claims of those other creditors, including trade creditors, holders of indebtedness or guarantees issued by these non-guarantor subsidiaries will generally have priority as to the assets of the non-guarantor subsidiary over our claims and equity interests. As a result, holders of our indebtedness, including the holders of the Notes, will be effectively subordinated to all those claims. We may merge one or more of the guarantor subsidiaries into Belden & Blake Corporation prior to December 31, 2004.

The rights of the holders of the Notes with respect to the collateral securing the Notes are substantially limited pursuant to the terms of the lien-ranking and voting provisions set forth in the indenture and the collateral trust agreement. Under those provisions, at any time that obligations that have the benefit of the first-priority liens are outstanding, any actions that may be taken in respect of the collateral, including the ability to cause the commencement of enforcement proceedings against the collateral and to control the conduct of such proceedings, and the approval of amendments to, releases of collateral from the lien of, and waivers of past defaults under, the security documents, will be at the direction of the holders of the obligations secured by the first-priority liens. The trustee, on behalf of the holders of the Notes, does not have the ability to control or direct such actions, even if the rights of the holders of the Notes are adversely affected. Our creditors with first-priority liens may have interests that are different from the interests of the holders of the Notes. Additional releases of collateral from the second-priority lien securing the Notes may be permitted under some circumstances. See “Description of the Collateral” and “Description of the Notes — Amendment, Supplement and Waiver.”

We have mortgaged real property as collateral for the Notes. Real property mortgaged as security to a lender may be subject to both known and unknown environmental risks. As a holder of a security interest in real property, under certain circumstances you could be held liable for the environmental costs of remediating or preventing releases or threatened releases of hazardous substances at the mortgaged property. Under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, a lender that participates in the management or operation of a mortgaged property can be liable as an owner or operator for certain environmental costs. In addition, if the mortgaged property were subject to material contamination, the value of the property could be substantially reduced and the lender may choose not to foreclose.

Your interest in the collateral may be adversely affected by the failure to perfect security interests in certain collateral acquired in the future.

The security interest in the collateral securing the Notes includes certain of our personal property and real property and that of our subsidiaries, a pledge of certain stock and other equity interests, intercompany notes and the proceeds of the foregoing, whether now owned or acquired or arising in the future. Applicable law requires that certain property and rights acquired after the grant of a general security interest can be perfected only at the time such property and rights are acquired and identified. We cannot assure you that the collateral trustee will monitor, or that we will inform the collateral trustee of, any future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. Such failure may result in the loss of the security interest therein or the priority of the security interest in favor of the Notes against third parties.

An investment in the Notes, as in any type of security, involves certain insolvency and bankruptcy considerations that investors should carefully consider. In the event we, or any of our subsidiary guarantors, were to become a debtor subject to insolvency proceedings under the United States Bankruptcy Code (“Bankruptcy Code”), it is likely delays in payment of the Notes and in enforcing remedies under the Notes, any guarantee or the liens securing the Notes and the guarantees would result. Provisions under the Bankruptcy Code or general principles of equity that could result in the impairment of your rights include, but are not limited to, the automatic stay, avoidance of preferential transfers by a trustee or debtor-in-possession, substantive consolidation, limitations on collectibility of unmatured interest or attorney fees and forced restructuring of the Notes.

Under the Bankruptcy Code, a secured creditor such as the trustee or collateral agent is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from such debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents, or profits of such collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The term “adequate protection” is not defined under bankruptcy law and, because of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the trustee or collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the Notes would be compensated for any delay in payment or loss of value of the collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the Notes, the holders of the Notes would have “undersecured claims.” Federal bankruptcy laws do not permit the payment or accrual of interest, costs, and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case. Furthermore, the undersecured portion of such claims are unsecured claims and have a lower priority than secured claims in a bankruptcy and there is a risk that the principal amount of such claims may not be repaid in full.

Under the Bankruptcy Code, a trustee or debtor-in-possession may generally recover payments or transfers of property of a debtor if such payment or transfer:


	•	was to or for the benefit of a creditor;

	•	was in payment of an antecedent debt owed before the transfer was made;

	•	was made while the debtor was insolvent;

	•	was within 90 days (or one year if the payment was to an “insider” of the debtor) before the filing of the bankruptcy case; and


	•	enabled the creditor to receive more than it would have received in a liquidation under Chapter 7 of the Bankruptcy Code if the transfer had not been made and the creditor received payment of the debt as provided in the Bankruptcy Code.

By way of example, if payments were made on the Notes prior to the filing of a bankruptcy case and a court subsequently determined that the value of the collateral pledged by the entity making the payment was less than the debt owed, such payments could be subject to avoidance as a preferential transfer.

A financial failure by us could also result in impairment of payment of the Notes if a bankruptcy court were to “substantively consolidate” us with our subsidiaries. If a bankruptcy court substantively consolidated us with our subsidiaries, the assets of each entity would be subject to the claims of creditors for all entities. Such a consolidation would expose the holders of the Notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base.

Forced restructuring of the Notes could occur through the “cram-down” provision of the Bankruptcy Code. Under this provision, the Notes could be restructured over the objections of holders of the Notes as to their general terms, primarily interest rate and maturity. Additionally, the Notes could be bifurcated into secured debt and unsecured debt if a bankruptcy court were to find that the debt owed by us exceeded the value of the collateral. If this were to occur, the unsecured portion of the debt could be afforded different treatment than the secured portion of the debt, including, but not limited to, the disallowance of the accrual of post-petition interest on the Notes.

In addition, the indenture provides that, in the event of a bankruptcy, the trustee and the collateral trustee may not object to a number of important matters following the filing of a bankruptcy petition so long as any first-priority lien debt is outstanding. After such a filing, the value of your collateral could materially deteriorate and you would be unable to raise an objection. The right of the holders of obligations secured by first-priority liens on the collateral to foreclose upon and sell the collateral upon the occurrence of an event of default also would be subject to limitations under applicable bankruptcy laws if we or any of our subsidiaries become subject to a bankruptcy proceeding.

Any future pledge of collateral in favor of the collateral trustee, including pursuant to security documents delivered after the date of the indenture, might be avoidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the holders of the Notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

A subsidiary guarantee and the liens securing a guarantee could be voided if it constitutes a fraudulent transfer under the bankruptcy code or similar state law.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee and the liens securing a guarantee can be voided, or claims under the guarantee and the liens securing a guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:


	•	was insolvent at the time of, or rendered insolvent by reason of, the incurrence of the guarantee;

	•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

	•	intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

A guarantee may also be voided, without regard to the above factors, if a court found that the guarantor entered into the guarantee with the actual intent to hinder, delay or defraud its creditors.

A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the guarantees. If a court were to void a subsidiary guarantee, you would no longer have a claim against that subsidiary guarantor. Sufficient funds to repay the Notes may not be available from other sources, including the remaining guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally a guarantor would be considered insolvent if:


	•	the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all its assets;

	•	the present fair saleable value of its assets is less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

	•	it could not pay its debts as they become due.

Each subsidiary guarantee will contain a provision intended to limit the guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its subsidiary guarantee to be a fraudulent transfer. This provision may not be effective to protect the subsidiary guarantee from being voided under fraudulent transfer law.

Upon the occurrence of certain change of control events, holders of the Notes may require us to repurchase all or any part of their Notes. We may not have sufficient funds at the time of the change of control to make the required repurchases of the Notes. Additionally, certain events that would constitute a “change of control” (as defined in the indenture governing the Notes) would constitute an event of default under our Senior Facilities that would, if it should occur, permit the lenders to accelerate the debt outstanding under our Senior Facilities and that, in turn, would cause an event of default under the indenture.

The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from oil and natural gas operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity.

We cannot assure you, however, that sufficient funds would be available at the time of any change of control to make any required repurchases of the Notes tendered and to repay debt under our senior secured credit facilities. Furthermore, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future. Any future credit agreements or other agreements relating to debt to which we may become a party will most likely contain similar restrictions and provisions.

If the Notes receive an investment grade rating, many of the covenants in the indenture governing the Notes will be suspended, thereby reducing some of the protections for holders of our Notes in the indenture.

If at any time the Notes receive investment grade ratings from both Standard & Poor’s Rating Services and Moody’s Investor Services, Inc., subject to certain additional conditions, many of the covenants in the indenture governing the Notes applicable to us and to our restricted subsidiaries, including the limitations on debt and restricted payments, will be suspended. While these covenants will be reinstated if we fail to maintain investment grade ratings on the Notes or in the event of a continuing default or event of default thereunder during the suspension period holders of our Notes will not have the

The terms of our new Senior Facilities, as well as the Hedges and the indenture relating to the Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.

Our new Senior Facilities and the Hedge Agreement contain, and any future refinancing of our Senior Facilities likely would contain, a number of restrictive covenants that impose significant operating and financial restrictions on us. Our Senior Facilities and, to some extent, the Hedge Agreement include covenants restricting, among other things, our ability to:


	•	incur additional debt;

	•	pay dividends and make investments, loans or advances;

	•	incur capital expenditures;

	•	create liens;

	•	use the proceeds from sales of assets and capital stock;

	•	enter into sale and leaseback transactions;

	•	enter into transactions with affiliates;

	•	transfer all or substantially all of our assets; and

	•	enter into merger or consolidation transactions.

Our Senior Facilities also include financial covenants, including requirements that we maintain:


	•	a minimum interest coverage ratio;

	•	a maximum total leverage ratio; and

	•	a maximum total first-priority senior leverage ratio to the PV-10 of our estimated proved reserves.

The indenture relating to the Notes also contains covenants including, among other things, restrictions on our ability to:


	•	incur additional indebtedness;

	•	pay dividends or make other distributions on stock, redeem stock or redeem subordinated obligations;

	•	make investments;

	•	create liens or other encumbrances; and

	•	sell or otherwise dispose of all or substantially all of our assets, or merge or consolidate with another entity.

A failure to comply with the covenants contained in our Senior Facilities or the indenture could result in an event of default (or an event of default under the Hedge Agreement which would result in an event of default under the Senior Facilities), which could materially and adversely affect our operating results and our financial condition. In the event of any default under our Senior Facilities or an event of default under the Hedge Agreement, the lenders under our Senior Facilities, or the Hedge counterparty, respectively, could elect to declare all borrowings outstanding or obligations thereunder, together with accrued and unpaid interest and fees, to be due and payable, and to require us to apply all of our available cash to repay the obligations owing to such entities, which would be an event of default under the Notes. In addition, our existing debt and any new debt may impose financial restrictions and other covenants on us that may be more restrictive than those applicable to the Notes. For more information on our Senior

Your ability to transfer the New Notes may be limited by the absence of an active trading market, and there is no assurance that any active true market will develop for the New Notes.

The New Notes are a new issue of securities for which there is no established public market. Although we have registered the New Notes under the Securities Act of 1933, we do not intend to apply for listing of the New Notes on any securities exchange or for quotation of the New Notes in any automated dealer quotation system. In addition, although the initial purchasers of the Outstanding Notes have informed us that they intend to make a market in the New Notes after the exchange offer, as permitted by applicable laws and regulations, they are not obliged to make a market in the New Notes, and they may discontinue their market-making activities at any time without notice. Therefore, we cannot assure you that an active market for the New Notes will develop or, if developed, that it will continue. Finally, if a large number of holders of Outstanding Notes do not tender Outstanding Notes or tender Outstanding Notes improperly, the limited amount of New Notes that would be issued and outstanding after we consummate the exchange offer could adversely affect the development of a market for these New Notes.

We are offering to exchange up to $192.5 million in the aggregate principal amount of New Notes for the same aggregate principal amount of Outstanding Notes. We are making the exchange offer for all of the Outstanding Notes. Your participation in the exchange offer is voluntary and you should carefully consider whether to accept this offer.

In connection with the issuance of the Outstanding Notes, we entered into an exchange and registration rights agreement. Under this agreement, we agreed to file under the Securities Act of 1933, no later than 90 days after the issuance of the Outstanding Notes, a registration statement with the Securities and Exchange Commission relating to a registered offer to exchange each Outstanding Note for a New Note having terms substantially identical in all material respects to such Note except that the New Note will be registered pursuant to an effective registration statement under the Securities Act of 1933 and will contain no provisions for additional interest. We further agreed to use our commercially reasonable efforts to:


	•	cause the registration statement to be declared effective under the Securities Act of 1933 as soon as practicable, but no later than 180 days after the original issuance of the Outstanding Notes;

	•	commence and complete the exchange offer promptly, but no later than 30 days after the registration statement has become effective; and

	•	keep the exchange offer open for at least 20 days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the Outstanding Notes and exchange New Notes for Outstanding Notes that are properly tendered and not withdrawn on or prior to the expiration date.

As soon as practicable after the registration statement is declared effective, we will offer to the holders of Outstanding Notes the opportunity to exchange their Outstanding Notes for New Notes registered under the Securities Act of 1933. Holders are eligible if they are not prohibited by any law or policy of the Securities and Exchange Commission from participating in this exchange offer. The New Notes will be substantially identical to the Outstanding Notes except that the New Notes will not contain terms with respect to transfer restrictions, registration rights or additional interest.

Under limited circumstances, we agreed to file a shelf registration statement for the resale of the Outstanding Notes within 30 days after such obligation to file arises. We also agreed to use our commercially reasonable efforts to cause the shelf registration statement to become or be declared effective no later than 120 days after the shelf registration statement has been filed and to keep the shelf registration statement effective for up to two years after its effective date or such time as there are no longer Outstanding Notes outstanding. The circumstances include if:


	•	a change in applicable interpretations by the staff of the Securities and Exchange Commission does not permit the transfer of New Notes without restriction under the Securities Act of 1933 by holders;

	•	a holder has notified us prior to the 20th business day following the consummation of the exchange offer that it may not resell the New Notes to the public without delivering a prospectus and the prospectus included in the registration statement that was used to register the New Notes is not appropriate or available for such resales; or

	•	a holder has notified us prior to the 20th business day following the consummation of the exchange offer that it is a broker-dealer and owns Outstanding Notes acquired directly from us or any of our affiliates.

If any of the following events occur, each of which is referred to as a registration default:


	•	if required, the shelf registration statement has not been filed with the Securities and Exchange Commission on or prior to the 30th calendar day after such event occurs which requires the filing of the shelf registration statement;

	•	if required, the shelf registration statement is not declared effective on or prior to the 120th calendar day following the event which requires the filing of the shelf registration statement;

	•	the exchange offer has not been completed on or prior to the 30th calendar day after the initial effective date of the exchange offer; or

	•	if either the registration statement of which this prospectus is a part or the shelf registration statement has been filed and declared effective but after its effective but thereafter is withdrawn by us or it has become subject to a stop order suspending its effectiveness without being succeeded immediately by a registration statement filed and declared effective.

The rate of the additional interest will be 0.25% per year for the first 90-day period immediately following the occurrence of a registration default, and such rate will increase by an additional 0.25% per year with respect to each subsequent 90-day period until all registration defaults have been cured, up to a maximum additional interest rate of 1.0% per year. Such additional interest will be in addition to any other interest payable from time to time with respect to the Outstanding Notes and the New Notes.

To exchange your Outstanding Notes for New Notes in the exchange offer, you will be required to make the following representations:


	•	you are not our “affiliate,” as defined in Rule 405 under the Securities Act of 1933;

	•	any New Notes will be acquired in the ordinary course of your business; and

	•	you are not engaged in and do not intend to engage in and you have no arrangement or understanding with any person to participate in a distribution of the New Notes.

In addition, in order for your Outstanding Notes to be included in the shelf registration statement, we may require you to provide information to be used in connection with the shelf registration statement. A holder who sells Outstanding Notes under the shelf registration statement generally will be required to be named as a selling securityholder in the related prospectus and to deliver a prospectus to purchasers. Such a holder will also be subject to the civil liability provisions under the Securities Act of 1933 in connection with such sales and will be bound by the provisions of the exchange and registration rights agreement that are applicable to such a holder, including indemnification obligations.

The description of the exchange and registration rights agreement contained in this section is a summary only. For more information, you should review the provisions of the exchange and registration rights agreement that we filed with the Securities and Exchange Commission as an exhibit to the registration statement of which this prospectus is a part.

Based on no-action letters issued to third parties by the Securities and Exchange Commission staff, we believe that New Notes may be offered for resale, resold and otherwise transferred by you without further compliance with the registration and prospectus delivery provisions of the Securities Act of 1933 if:


	•	you are not our “affiliate” within the meaning of Rule 405 under the Securities Act;

	•	such New Notes are acquired in the ordinary course of your business; and

	•	you are not participating, do not intend to participate and have no arrangement or understanding with any person to participate in a distribution of the New Notes.

The Securities and Exchange Commission, however, has not considered the exchange offer for the New Notes in the context of a no-action letter, and the Securities and Exchange Commission may not make a similar determination as in the no-action letters issued to these third parties.

If you tender in the exchange offer with the intention of participating in any manner in a distribution of the New Notes, you


	•	cannot rely on such interpretations by the Securities and Exchange Commission staff; and

	•	must comply with the registration and prospectus delivery requirements of the Securities Act of 1933 in connection with a secondary resale transaction.

Unless an exemption from registration is otherwise available, any security holder intending to distribute New Notes should ensure that such distribution is covered by an effective registration statement under the Securities Act of 1933. The registration statement should contain the selling security holder’s information required by Item 507 or 508, as applicable, of Regulation S-K under the Securities Act of 1933.

This prospectus may be used for an offer to resell, resale or other transfer of New Notes only as specifically described in this prospectus. Failure to comply with the registration and prospectus delivery requirements by a holder subject to these requirements could result in that holder incurring liability for which it is not indemnified by us. If you are a broker-dealer, you may participate in the exchange offer only if you acquired the Outstanding Notes as a result of market-making activities or other trading activities. Each broker-dealer that receives New Notes for its own account in exchange for Outstanding Notes, where such Outstanding Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge in the letter of transmittal that it will deliver a prospectus in connection with any resale of the New Notes. Please read the section captioned “Plan of Distribution” for more details regarding the transfer of New Notes.

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any Outstanding Notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue New Notes in principal amount equal to the principal amount of Outstanding Notes surrendered under the exchange offer. Outstanding Notes may be tendered only for New Notes and only in integral multiples of $1,000.

The exchange offer is not conditioned upon any minimum aggregate principal amount of Outstanding Notes being tendered for exchange.

As of the date of this prospectus, $192.5 million in aggregate principal amount of the Outstanding Notes are outstanding. This prospectus is being sent to The Depositary Trust Company (“DTC”), the sole registered holder of the Outstanding Notes, and to all persons that we can identify as beneficial owners of the Outstanding Note. There will be no fixed record date for determining registered holders of Outstanding Notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the exchange and registration rights agreement, the applicable requirements of the Securities Act of 1933 and the Securities Exchange Act of 1934 and the rules and regulations of the Securities and Exchange Commission. Outstanding Notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These Outstanding Notes will be entitled to the rights and benefits such holders have under the indenture relating to the Notes and the exchange and registration rights agreement.

We will be deemed to have accepted for exchange properly tendered Outstanding Notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the exchange and registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the New Notes from us.

If you tender Outstanding Notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of Outstanding Notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “— Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any Outstanding Notes that we do not accept for exchange for any reason without expense to their tendering holder as promptly as practicable after the expiration or termination of the exchange offer.

The exchange offer will expire at 5:00 p.m. New York City time on January 31, 2005, unless, in our sole discretion, we extend it.

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. During any such extensions, all Outstanding Notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of Outstanding Notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

If any of the conditions described below under “— Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:


	•	to delay accepting for exchange any Outstanding Notes,

	•	to extend the exchange offer, or

	•	to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the exchange and registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of Outstanding Notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the Outstanding Notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we will extend the exchange offer if the exchange offer would otherwise expire during such period.

We will not be required to accept for exchange, or exchange any New Notes for, any Outstanding Notes if the exchange offer, or the making of any exchange by a holder of Outstanding Notes, would violate applicable law or any applicable interpretation of the staff of the Securities and Exchange Commission. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting Outstanding Notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the Outstanding Notes of any holder that has not made to us the representations described under “— Purpose and Effect of the Exchange Offer,” “— Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable Securities and Exchange Commission rules, regulations or

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any Outstanding Notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the Outstanding Notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any Outstanding Notes tendered, and will not issue New Notes in exchange for any such Outstanding Notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

In order to participate in the exchange offer, you must properly tender your Outstanding Notes to the exchange agent as described below. It is your responsibility to properly tender your Outstanding Notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your Outstanding Notes, please call the exchange agent, whose address and phone number are set forth in “Summary — The Exchange Offer — Exchange Agent.”

Only a holder of Outstanding Notes may tender such Outstanding Notes in the exchange offer. To tender in the exchange offer, a holder must:


	•	complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal;

	•	have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires; and

	•	mail or deliver such letter of transmittal or facsimile to the exchange agent in sufficient time for receipt by the exchange agent prior to 5:00 p.m., New York City time, on the expiration date; or

	•	comply with the automated tender offer program procedures of DTC described below.


	•	the exchange agent must receive Outstanding Notes along with the letter of transmittal;

	•	the exchange agent must receive prior to 5:00 p.m., New York City time, on the expiration date, a timely confirmation of book-entry transfer of such Outstanding Notes into the exchange agent’s account at DTC according to the procedure for book-entry transfer described below or a properly transmitted agent’s message; or

	•	the holder must comply with the guaranteed delivery procedures described below.

To be tendered effectively, the exchange agent must receive any physical delivery of the letter of transmittal and other required documents at its address indicated on the cover page of the letter of transmittal. The exchange agent must receive such documents prior to 5:00 p.m., New York City time, on the expiration date.

The tender by a holder that is not withdrawn prior to 5:00 p.m., New York City time, on the expiration date will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

THE METHOD OF DELIVERY OF OUTSTANDING NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT YOUR ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, WE RECOMMEND THAT YOU USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE 5:00 P.M., NEW YORK CITY TIME, ON THE EXPIRATION DATE. YOU SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR OUTSTANDING NOTES TO US. YOU MAY REQUEST YOUR BROKERS, DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR YOU.

If you beneficially own Outstanding Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender those notes, you should contact the registered holder promptly and instruct it to tender, on your behalf. If you are a beneficial owner and wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your Outstanding Notes, either:


	•	make appropriate arrangements to register ownership of the Outstanding Notes in your name; or

	•	obtain a properly completed bond power from the registered holder of Outstanding Notes.

The transfer of registered ownership, if permitted under the indenture for the Notes, may take considerable time and may not be completed prior to the expiration date.

You must have signatures on a letter of transmittal or a notice of withdrawal (as described below) guaranteed by a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States, or an “eligible guarantor institution” within the meaning of Rule l7Ad-15 under the Securities Exchange Act of 1934. In addition, such entity must be a member of one of the recognized signature guarantee programs identified in the letter of transmittal.

If the letter of transmittal is signed by a person other than the registered holder of any Outstanding Notes, the Outstanding Notes must be endorsed or accompanied by a properly completed bond power. The endorsement or bond power, as applicable, must be signed by the registered holder as the registered holder’s name appears on the Outstanding Notes. A member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution must guarantee the signature on the endorsement or bond power, as applicable.

If the letter of transmittal or any Outstanding Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity those persons should so indicate when signing. Unless waived by us, they should also submit evidence satisfactory to us of their authority to deliver the letter of transmittal.

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s automated tender offer program (“ATOP”) to tender. Participants in the

The term “agent’s message” means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation to the effect that:


	•	DTC has received an express acknowledgment from a participant in its automated tender offer program that is tendering Outstanding Notes that are the subject of such book-entry confirmation;

	•	such participant has received and agrees to be bound by the terms of the letter of transmittal or, in the case of an agent’s message relating to guaranteed delivery, that such participant has received and agrees to be bound by the applicable notice of guaranteed delivery; and

	•	the agreement may be enforced against such participant.

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered Outstanding Notes and withdrawal of tendered Outstanding Notes. Our determination will be final and binding. We reserve the absolute right to reject any Outstanding Notes not properly tendered or any Outstanding Notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular Outstanding Notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of Outstanding Notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of Outstanding Notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of Outstanding Notes will not be deemed made until such defects or irregularities have been cured or waived. Any Outstanding Notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date.

In all cases, we will issue New Notes for Outstanding Notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:


	•	a book-entry confirmation of such Outstanding Notes into the exchange agent’s account at DTC; and

	•	a properly transmitted agent’s message.

If we do not accept any tendered Outstanding Notes for exchange or if Outstanding Notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged Outstanding Notes will be returned without expense to their tendering holder. Such non-exchanged Outstanding Notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the exchange offer.

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:


	•	you are not our “affiliate,” as defined in Rule 405 under the Securities Act of 1933;

	•	any New Notes will be acquired in the ordinary course of your business; and

	•	you are not engaged in and do not intend to engage in and you have no arrangement or understanding with any person to participate in a distribution of the New Notes.

The exchange agent will establish an account with respect to the Outstanding Notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution participating in DTC’s system may make book-entry delivery of Outstanding Notes by causing DTC to transfer such Outstanding Notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. Holders of Outstanding Notes who are unable to deliver confirmation of the book-entry tender of their Outstanding Notes into the exchange agent’s account at DTC or all other documents required by the letter of transmittal to the exchange, agent on or prior to 5:00 p.m., New York City time, on the expiration date must tender their Outstanding Notes according to the guaranteed delivery procedures described below.

If you wish to tender your Outstanding Notes but your Outstanding Notes are not immediately available or you cannot deliver your Outstanding Notes, the letter of transmittal or any other required documents to the exchange agent or comply with the applicable procedures under DTC’s ATOP system prior to the expiration date, you may tender if:


	•	the tender is made through a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution;

	•	prior to the expiration date, the exchange agent receives from such member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., commercial bank or trust company having an office or correspondent in the United States, or eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery by facsimile transmission, mail or hand delivery or a properly transmitted agent’s message and notice of guaranteed delivery:


	—	setting forth your name and address, the registered number(s) of your Outstanding Notes and the principal amount of Outstanding Notes tendered,

	—	stating that the tender is being made thereby, and

	—	guaranteeing that, within three (3) New York Stock Exchange, or NYSE, trading days after the expiration date, the letter of transmittal or facsimile thereof, together with the Outstanding Notes or a book-entry confirmation, and any other documents required by the letter of transmittal will be deposited by the eligible guarantor institution with the exchange agent, and

	—	the exchange agent receives such properly completed and executed letter of transmittal or facsimile thereof, as well as all tendered Outstanding Notes in proper form for transfer or a book-entry confirmation, and all other documents required by the letter of transmittal, within three (3) NYSE trading days after the expiration date.

Upon request to the exchange agent, a notice of guaranteed delivery will be sent you if you wish to tender your Outstanding Notes according to the guaranteed delivery procedures described above.

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m. New York City time on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn Outstanding Notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any Outstanding Notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any Outstanding Notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the Outstanding Notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn Outstanding Notes by following the procedures described under “— Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:


	•	Securities and Exchange Commission registration fees;

	•	fees and expenses of the exchange agent and trustee;

	•	accounting and legal fees and printing costs; and

	•	related fees and expenses.

We will pay all transfer taxes, if any, applicable to the exchange of Outstanding Notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of Outstanding Notes under the exchange offer.

If you do not exchange New Notes for your Outstanding Notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the Outstanding Notes. In general, you may not offer or sell the Outstanding Notes unless they are registered under the Securities Act of 1933, or if the offer or sale is exempt from registration under the Securities Act of 1933 and applicable state securities laws. Except as required by the exchange and registration rights agreement, we do not intend to register resales of the Outstanding Notes under the Securities Act of 1933.

We will record the New Notes in our accounting records at the same carrying value as the Outstanding Notes. This carrying value is the aggregate principal amount of the Outstanding Notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered Outstanding Notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any Outstanding Notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered Outstanding Notes.

The exchange offer is intended to satisfy our obligations under the exchange and registration rights agreement. We will not receive any proceeds from the issuance of the New Notes in the exchange offer. In consideration for issuing the New Notes as contemplated by this prospectus, we will receive Outstanding Notes in a like principal amount. The form and terms of the New Notes are identical in all respects to the form and terms of the Outstanding Notes, except the New Notes will be registered under the Securities Act of 1933 and will not contain restrictions on transfer, registration rights or provisions for additional interest. Outstanding Notes surrendered in exchange for the New Notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the New Notes will not result in any change in outstanding indebtedness.

Our consolidated ratio of earnings to fixed charges from continuing operations for each of the periods indicated are as follows:


(1)	The ratio of earnings to fixed charges has been computed by dividing earnings available for fixed charges (earnings from continuing operations before income taxes and fixed charges) by fixed charges (interest expense and amortization of debt issuance costs). Interest expense includes the portion of operating rental expense that we believe is representative of the interest component of rental expense.

(2)	Includes the pro forma effect of the borrowings to refinance our indebtedness in connection with the Merger, the issuance of the Outstanding Notes and the incurrence of indebtedness under the Senior Facilities as if all such transactions had occurred on January 1, 2003.

(3)	The pro forma deficiency at September 30, 2004 was $6.9 million.

You should read this table in conjunction with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and the related notes thereto.

The following tables set forth certain of our pro forma financial information after giving effect to the Transactions. The Transactions include the Merger, the issuance of the Notes and incurrence of indebtedness under the Senior Facilities and the application of proceeds therefrom (collectively, the “Merger and Refinancing”). The unaudited consolidated balance sheet as of September 30, 2004 appearing elsewhere herein reflects the preliminary allocation of the purchase price to the assets acquired and liabilities assumed by the successor company. The unaudited pro forma consolidated statement of operations for the year ended December 31, 2003 has been derived from our audited consolidated financial statements for the year ended December 31, 2003. The unaudited pro forma consolidated statement of operations for the nine months ended September 30, 2004 has been derived from our unaudited financial statements for the nine month period ended September 30, 2004. The pro forma statements of operations give effect to the Transactions as if each occurred on January 1, 2003.

The unaudited pro forma financial statements should be read in conjunction with the accompanying notes to the unaudited pro forma financial statements, our historical consolidated financial statements and related notes, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other financial information contained in this prospectus. The pro forma information presented herein does not purport to be indicative of the financial position or results of operations that would have actually occurred had the Transactions occurred on the dates indicated or which may occur in the future. All pro forma adjustments are based on preliminary estimates and assumptions and are subject to revision to reflect, among other things, the final allocation of the purchase price. There can be no assurance that such changes will not be material.

(a) Represents increased depreciation, depletion and amortization relating to the basis of property and equipment associated with the preliminary purchase price allocation for the Merger as if it occurred on January 1, 2003.

(b) Represents additional accretion charges resulting from the revaluation of fair value based upon management’s assessment of certain factors as they relate to our asset retirement obligation.

(c) Represents the adjustment to historical interest expense on debt to be retired and interest expense on debt assumed and issued in connection with the Merger and Refinancing at the applicable interest rates under the Notes and the Senior Facilities. Assumes the issuance of $55 million aggregate amount of letters of credit.

(d) To adjust for the provision for income taxes as a result of the pro forma adjustments.

The summary historical consolidated financial data set forth below is derived from our consolidated financial statements. The summary historical consolidated financial data as of and for each of the years ended December 31, 1999, 2000, 2001, 2002 and 2003 have been derived from our audited Consolidated Financial Statements. The summary historical consolidated financial data as of and for the nine months ended September 30, 2003 and the successor company 91 day period from July 2, 2004 to September 30, 2004 and the predecessor company for the 183 day period from January 1, 2004 to July 1, 2004 have been derived from our unaudited consolidated financial statements, which were prepared on the same basis as our audited consolidated financial statements and, in the opinion of management, include all adjustments considered necessary for a fair presentation of our financial position and results of operations for such periods. The results from any interim period are not necessarily indicative of the results that may be expected for a full fiscal year. Historical results are not necessarily indicative of the results to be expected in the future. The data presented below should be read together with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related notes thereto.

The following discussion and analysis of financial condition and results of operations should be read in conjunction with “Selected Historical Financial Data” and the Consolidated Financial Statements and notes thereto presented elsewhere in this prospectus. We follow the successful efforts method of accounting for our oil and gas properties. See “Summary of Accounting Policies,” included in Note 1 to the Consolidated Financial Statements.

We are a privately held company wholly owned by Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”). Capital C recently acquired us pursuant to an Agreement and Plan of Merger. The Merger was completed on July 7, 2004. Capital C is a controlled affiliate of Carlyle/ Riverstone.

At December 31, 2003, our total estimated proved reserves related to continuing operations were 355 Bcfe. Natural gas comprised approximately 90% of our estimated proved reserves, and 66% of our estimated proved reserves were classified as proved developed. Substantially all of our reserves are located in shallow, highly developed, blanket formations with long-lived, stable production profiles. At December 31, 2003 our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coal bed methane properties accounted for 38% and 10%, respectively.

In connection with the acquisition by Capital C, our existing indebtedness was refinanced. The principal elements of the refinancing include the Senior Facilities, consisting of a $100 million term facility, a $30 million revolving facility and a $40 million letter of credit facility, and the Notes.

During the periods discussed, we earned revenue through the production and sale of oil and natural gas and, to a lesser extent, from gas gathering and marketing. We recently sold Arrow and substantially all of our interests, or rights to our interests, in our TBR operations. Both of these transactions were classified as discontinued operations. Historical information has been restated to remove the TBR properties and Arrow from continuing operations.

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We utilize derivative instruments on a portion of our oil and natural gas production to reduce the volatility of oil and natural gas prices and to protect cash flow available for our development drilling program. In connection with the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term hedging program with J. Aron. We anticipate that the Hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves and will range from 52% to 84% of such expected production in any year.

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 $4.94 per Mcf in the first nine months of 2003. The average price realized for our natural gas in 2003 decreased $0.03 per Mcf to $4.92 per Mcf compared to $4.95 per Mcf in 2002. The monthly average settle for natural gas trading on the NYMEX increased from $5.66 per Mmbtu in the first nine months of 2003 to $5.81 per Mmbtu in the first nine months of 2004 and increased from $3.22 per Mmbtu in 2002 to $5.39 per Mmbtu in 2003. Our selling price of natural gas is generally higher than the NYMEX price due to the favorable regional basis received throughout our areas of operations along with a favorable Btu content of our gas. The remainder of the difference is due to fixed

The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, the discontinued operations have been excluded. See Note 4 to the Consolidated Financial Statements.

The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the years indicated, excluding discontinued operations. However, it does not exclude dispositions of properties that did not qualify as discontinued operations. See Note 4 to the Consolidated Financial Statements:


(1)	Average prices reflect the effect of hedges in effect during the periods indicated.

(2)	Operating margin (per Mcfe) is defined as average price less production expense and production taxes.

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 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

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.

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 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.

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 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.

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

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.

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.

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 due 2012 (the “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.

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 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.

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.

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

In the Merger, each issued and outstanding share of our common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under our prior credit facility were repaid. In connection with the Consent Solicitation and Tender Offer we previously announced, over 98% of the $225 million aggregate principal amount of our 9 7/8% Senior Subordinated Notes due 2007 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) our 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 our assets and are guaranteed by two of our 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 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 are 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.

In connection with the Merger we 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 became our new President and Chief Executive Officer and B. Dee Davis and W. Mac Jensen joined us as Senior Vice Presidents. All of our former directors resigned and Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard were elected to our Board of Directors. 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. On December 16, 2004, we accepted the resignations of Frost W. Cochran, David M. Carmichael, B. Dee Davis, Jr., and W. Mac Jensen from all of their respective positions as officers and directors (as applicable) of the Company and its subsidiaries. Also on December 16, 2004, James A. Winne III became our new Chief Executive Officer and Chairman of the Board of Directors and Michael Becci became our new President and Chief Operating Officer. The size of our Board of Directors is now six.

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

As a result of the amount of our consolidated excess cash flow (as defined in our credit agreement) for the second half of 2004, we anticipate having a mandatory prepayment requirement under our credit facility. This payment would be required to be made on or before April 15, 2005. We elected to prepay $10 million on December 16, 2004. As of December 17, 2004 the outstanding balance on our term credit facility was approximately $90 million and our cash balance was approximately $12 million.

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.

The following table sets forth financial data for the periods indicated. Dollars are stated in thousands and percentages are stated as a percentage of total revenues.

Net operating revenues decreased from $104.0 million in 2002 to $95.1 million in 2003. The decrease was due to lower gas sales revenues of $5.6 million, lower oil sales revenues of $266,000 and lower revenues from gas gathering and marketing of $3.0 million.

Gas volumes sold decreased 1.1 Bcf (7%) from 15.9 Bcf in 2002 to 14.8 Bcf in 2003 resulting in a decrease in gas sales revenues of approximately $5.2 million. Oil volumes sold decreased approximately 109,000 Bbls (21%) from 522,000 Bbls in 2002 to 413,000 Bbls in 2003 resulting in a decrease in oil sales revenues of approximately $2.5 million. The oil and gas volume decreases were due to the sales of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of the wells partially offset by production from wells drilled in 2002 and 2003.

The average price realized for our natural gas decreased $0.03 per Mcf to $4.92 per Mcf in 2003 compared to 2002, which decreased gas sales revenues in 2003 by approximately $445,000. As a result of our hedging activities, gas sales revenues were decreased by $10.3 million ($0.69 per Mcf) in 2003 and increased by $21.6 million ($1.36 per Mcf) in 2002. The average price paid for our oil increased from $22.72 per barrel in 2002 to $28.06 per barrel in 2003, which increased oil sales revenues by approximately $2.2 million.

The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis decreased from $3.60 per Mcfe in 2002 to $3.59 per Mcfe in 2003.

The decrease in gas gathering and marketing revenues was primarily the result of decreased gas marketing activity, the termination of a gas marketing contract and lower margins on a gathering system in Pennsylvania.

Production expense decreased $230,000 from $20.2 million in 2002 to $20.0 million in 2003. This decrease was primarily due to the sales of wells in Ohio and Pennsylvania during 2002, partially offset by higher operating costs incurred as a result of colder temperatures and greater amounts of snow during the first quarter of 2003 coupled with increased costs to stimulate production on declining wells in the higher oil and natural gas price environment of 2003. These efforts increased production volumes during 2003 but also had the effect of increasing the per unit cost. The average production cost increased from $1.07 per Mcfe in 2002 to $1.16 per Mcfe in 2003. The per unit increase was primarily due to the higher costs incurred during 2003 as discussed above and certain fixed costs spread over fewer volumes in 2003.

Production taxes increased $660,000 from $1.8 million in 2002 to $2.4 million in 2003 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. Average per unit production taxes increased 50% from $0.09 per Mcfe in 2002 to $0.14 per Mcfe in 2003 primarily due to a 56% increase in the selling price of natural gas in 2003, excluding the effects of hedging.

Exploration expense decreased $2.0 million from $8.8 million in 2002 to $6.8 million in 2003 due to a decrease in seismic costs of $1.1 million, a decrease of $252,000 in land leasing expense and a decrease in employment and other compensation related expenses.

Depreciation, depletion and amortization decreased by $3.2 million from $21.3 million in 2002 to $18.1 million in 2003. This decrease was primarily due to a $286,000 reduction in amortization of loan costs, a $404,000 reduction in the amortization of nonconventional fuel source tax credits and a decrease in depletion expense. Depletion expense decreased $2.0 million (12%) from $16.6 million in 2002 to $14.6 million in 2003 due to lower oil and gas volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.87 per Mcfe in 2002 to $0.85 per Mcfe in 2003, primarily due to the effect of the adoption of SFAS 143. The basis used to calculate depletion expense for oil and gas properties was

Impairment of oil and gas properties was $896,000 in 2003 due to impairment of acreage of $475,000 in certain areas and an impairment of $421,000 in one of our smaller producing property pools. The impairments reduced the property’s book value to its estimated fair value.

Accretion expense was $343,000 in 2003 as a result of the adoption of SFAS 143 at the beginning of 2003.

Derivative fair value gain was $319,000 in 2003 related to certain derivative instruments that are not designated as cash flow hedges. The gain reflects the changes in fair value of those instruments.

We recorded severance and other nonrecurring charges of $923,000 in 2002 which were primarily related to employment reductions. In 2002, a total of 28 positions were eliminated when we combined our Pennsylvania/ New York District with our Ohio District to form a new “Appalachian District.” These actions were necessary to capitalize on operational and administrative efficiencies and bring our employment level in line with current and anticipated future staffing.

Interest expense increased $1.1 million (5%) from $22.5 million in 2002 to $23.6 million in 2003. This increase was due to an increase in average outstanding borrowings and higher blended interest rates.

Income tax expense decreased $2.1 million from $5.3 million in 2002 to $3.2 million in 2003. The decrease in expense is due to a decrease in income from continuing operations and a lower effective tax rate in 2003.

Loss from discontinued operations increased from a net loss of $6.5 million in 2002 to a loss of $10.7 million in 2003. Discontinued operations relate to the New York Medina wells sold in 2002 and the TBR and Arrow assets sold in the second quarter of 2004. The increase is due primarily to a $7.9 million ($5.2 million net of tax benefit) increase in loss from the TBR assets as a result of higher TBR exploration expense in 2003 and an impairment recorded on undeveloped TBR acreage in 2003. This increase was partially offset by a $1.2 million decrease in loss from the New York Medina wells as a result of the $3.2 million ($1.8 million net of tax benefit) loss recorded on the sale in 2002.

Net operating revenues decreased from $109.0 million in 2001 to $104.0 million in 2002. The decrease was due to lower oil sales revenues of $3.0 million, lower revenues from gas gathering and marketing of $6.0 million, partially offset by higher gas sales revenues of $4.0 million.

Gas volumes sold decreased 1.3 Bcf (7%) from 17.2 Bcf in 2001 to 15.9 Bcf in 2002 resulting in a decrease in gas sales revenues of approximately $5.6 million. Oil volumes sold decreased approximately 122,000 Bbls (19%) from 644,000 Bbls in 2001 to 522,000 Bbls in 2002 resulting in a decrease in oil sales revenues of approximately $2.8 million. The oil and gas volume decreases were due to the sales of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of the wells partially offset by production from wells drilled in 2001 and 2002.

The average price realized for our natural gas increased $0.60 per Mcf to $4.95 per Mcf in 2002 compared to 2001, which increased gas sales revenues in 2002 by approximately $9.5 million. As a result of our hedging activities, gas sales revenues were increased by $21.6 million ($1.36 per Mcf) in 2002 and $4.5 million ($0.26 per Mcf) in 2001. The average price paid for our oil decreased from $23.04 per barrel in 2001 to $22.72 per barrel in 2002, which decreased oil sales revenues by approximately $170,000.

The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis increased 15% from $3.14 per Mcfe in 2001 to $3.60 per Mcfe in 2002.

The decrease in gas gathering and marketing revenues was due to a decrease in gas marketing activity and the termination of a gas marketing contract.

Production expense decreased $1.0 million (5%) from $21.2 million in 2001 to $20.2 million in 2002 primarily due to the sales of wells in Ohio and Pennsylvania in 2002. The average production cost increased from $1.01 per Mcfe in 2001 to $1.07 per Mcfe in 2002. The per unit increase was primarily due to certain fixed costs spread over fewer volumes in 2002.

Production taxes decreased $509,000 from $2.3 million in 2001 to $1.8 million in 2002 primarily due to the wells sold during 2002. Average per unit production taxes decreased 14% from $0.11 per Mcfe in 2001 to $0.09 per Mcfe in 2002 primarily due to a 12% decrease in the selling price of natural gas in 2002, excluding the effects of hedging.

Exploration expense increased $2.9 million from $5.9 million in 2001 to $8.8 million in 2002 due to an increase in expired or dropped leases of $791,000, a $194,000 increase in delay rental expense, a $1.0 million increase in land leasing expense and a $742,000 increase in geological and geophysical expense.

Depreciation, depletion and amortization decreased by $3.8 million from $25.1 million in 2001 to $21.3 million in 2002. This decrease was primarily due to a $570,000 reduction in amortization of loan costs from the extension of our revolving credit facility’s final maturity date, a $173,000 reduction in amortization of non-compete covenants which expired in 2001, a $323,000 reduction in the amortization of nonconventional fuel source tax credits in 2002 and a decrease in depletion expense. Depletion expense decreased $2.5 million (13%) from $19.1 million in 2001 to $16.6 million in 2002. Depletion per Mcfe decreased from $0.91 per Mcfe in 2001 to $0.87 per Mcfe in 2002. These decreases were primarily the result of a lower amortization rate per Mcfe due to higher reserves resulting from higher oil and gas prices at year-end 2002.

Impairment of oil and gas properties and other assets decreased $1.4 million due to no impairment in 2002.

We recorded severance and other nonrecurring charges of $923,000 in 2002 and $2.0 million in 2001 which were primarily related to employment reductions. In 2002, a total of 28 positions were eliminated when we combined our Pennsylvania/ New York District with our Ohio District to form a new “Appalachian District.” These actions were necessary to capitalize on operational and administrative efficiencies and bring our employment level in line with current and anticipated future staffing.

Interest expense decreased $2.6 million (10%) from $25.1 million in 2001 to $22.5 million in 2002. This decrease was due to a decrease in average outstanding borrowings and lower blended interest rates.

Income tax expense increased $5.4 million from a benefit of $188,000 in 2001 to income tax expense of $5.3 million in 2002. The increase in expense is due to an increase in income from continuing operations and income tax benefits of $2.7 million recorded in 2001. During 2001, we concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which we now believe we can fully utilize.

Loss from discontinued operations increased from a net loss of $733,000 in 2001 to a loss of $6.5 million in 2002. Discontinued operations relate to the New York Medina wells sold in 2002 and the TBR and Arrow assets sold in the second quarter of 2004. The increase is due primarily to a $5.4 million ($3.5 million net of tax benefit) increase in loss from the TBR assets as a result of higher TBR exploration expense in 2002 and a $3.2 million ($1.8 million net of tax benefit) loss recorded on the sale of the New York Medina wells in 2002.

We expect that our primary sources of cash in 2004 will be from funds generated from operations, from borrowings under the Senior Facilities and from the proceeds from the issuance of the Outstanding Notes and from the sale of assets. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Senior Facilities, will be adequate to meet our future liquidity needs for the foreseeable future.

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 the private offering of the 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. 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 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 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.

Our operating activities provided cash flows of $26.2 million during 2003 compared to $50.3 million in 2002. The decrease was primarily due to lower cash received for oil and gas revenues (net of hedging) of $12 million, lower margins from gas gathering and marketing of $1.6 million, higher interest expense of $1.1 million and changes in working capital items of $10 million. During 2003, working capital from continuing operations increased $431,000 from a deficit of $7.5 million at December 31, 2002 to a deficit of $7.1 million at December 31, 2003. The increase was primarily due to an increase in liability for the fair value of derivatives of $9.0 million which was partially offset by an increase in accounts receivable of $2.9 million, an increase in deferred tax assets of $2.7 million, an increase in other assets of $1.1 million and a decrease in accrued expenses of $2.9 million.

In the second half of 2004, we plan to spend approximately $12.5 million on our drilling and other capital expenditures related to continuing operations. We plan to drill 63 wells primarily in the Medina, Clarendon, Coalbed Methane and Antrim formations during the second half of the year.

The following table sets forth our total capital expenditures for each of the years ending December 31, 2003, 2002 and 2001.

Our Senior Facilities are 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 for letters of credit to collateralize the Hedges and other hedging transactions; and a six year $40 million letter of credit facility to collateralize the Hedges and other hedging transactions. The Senior Facilities are secured by a first-priority lien on certain of our assets and those of any guarantor subsidiaries. See “Description of the Collateral” and “Description of Other Indebtedness,” for a discussion of the Senior Facilities and the relative rights of the lenders under the Senior Facilities, the counterparty under the Hedge Agreement and the holders of the Notes with respect to collateral securing their obligations.

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. To manage our exposure to natural gas or oil price volatility, we may partially hedge our physical gas or oil sales prices by selling futures contracts on the NYMEX or 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, collars or options.

We are a party to a long-term hedging program through 2013 with J. Aron. The Hedges primarily take the form of monthly settled fixed price swaps in respect of the settlement prices for the market standard NYMEX futures contracts on natural gas and crude oil. We pay a NYMEX-based floating price per Mmbtu, in the case of Hedges on natural gas, and pay a NYMEX-based floating price per Bbl in the case of Hedges on crude oil for each month during the term of the Hedges and receive a fixed price per Mmbtu or Bbl (as the case may be), according to a monthly schedule of fixed prices, which were established upon the closing of the Merger. In addition to the monthly settled fixed prices swaps, our current existing commodity hedge transactions for the remainder of 2004 and for 2005 were reestablished with J. Aron in connection with the Merger and now constitute part of the Hedges. We anticipate that the Hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves and will range from 52% to 84% of such expected production in any year.

We are required to maintain the Hedges or a similar hedging program during the term of the Senior Financings. The Hedges are documented under the Hedge Agreement, which is based on the standard ISDA form with customized credit terms. See “Description of Other Indebtedness — Post-Merger Debt — The Hedges.” Initial collateral requirements and ongoing margin requirements (based on market movements) under the Hedges are satisfied by letters of credit issued under the Senior Facilities, with an aggregate cap of $55 million. To support any exposure in excess of amounts supported by the letters of credit, we have granted J. Aron a second-priority lien in the collateral securing the Senior Financings and the Notes. The Hedges are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes on a second-priority senior secured basis. See “Description of Other Indebtedness — Post-Merger Debt — The Hedges.” We may also enter into hedges with other third parties.

The following tables reflect the crude oil and natural gas 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.

The average price of our natural gas increased from $4.35 per Mcf in 2001 to $4.95 per Mcf in 2002, then decreased to $4.92 in 2003. During 2001, the price paid for our crude oil fluctuated between a low of $13.50 per barrel and a high of $28.50 per barrel, with an average price of $23.04 per barrel. During 2002, the price paid for our crude oil increased from $16.25 per barrel at the beginning of the year to $27.50 per barrel at year end, with an average price of $22.72 per barrel. During 2003, the price paid for our crude oil fluctuated between a low of $22.00 per barrel and a high of $34.25 per barrel, with an average price of $28.06 per barrel. These prices reflect average prices for oil and gas sales of our continuing operations. The natural gas prices include the effect of our hedging activity.

The price of oil and natural gas has a significant impact on our results of operations. Oil and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. Costs to drill, complete and service wells can fluctuate based on demand for these services which is generally influenced by high or low commodity prices. Our costs and expenses may be subject to inflationary pressures if oil and gas prices are favorable.

A large portion of our natural gas is sold subject to market sensitive contracts. Natural gas price risk has historically been mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or collars. Natural gas price hedging decisions have historically been made in the context of our strategic objectives, taking into account the changing fundamentals of the natural gas marketplace.

We have various commitments primarily related to leases for office space, vehicles, natural gas compressors and computer equipment. We expect to fund these commitments with cash generated from operations. We have no off-balance sheet debt or other such unrecorded obligations, and have not guaranteed the debt of any other party.

The following table summarizes our contractual obligations at December 31, 2003.

Our long-term debt obligations will change as a result of the refinancing of our existing long-term debt. See “Description of Other Indebtedness.”

In addition to the items above, we have a retention plan, a severance plan and a change of control plan. In connection with the Merger, pursuant to the Chief Executive Officer’s employment agreement and other related arrangements, our Chief Executive Officer received a special retention bonus of $1.0 million as well as certain other expense reimbursements and benefits and was paid a $330,000 annual retention bonus on July 1, 2004.

We have entered into joint operating agreements, area of mutual interest agreements and joint venture agreements with other companies. These agreements may include drilling commitments or other obligations in the normal course of business.

In the normal course of business, we have performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. We also have letters of credit with our hedging counterparty.

We have certain other commitments and uncertainties related to our normal operations, including any obligation to plug wells.

The interest rate risk relates to the debt under our new Senior Facilities as well as any new debt financing needed to fund capital requirements. 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 our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior subordinated 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, September 30, 2003 or December 31, 2003, 2002 and 2001. Pursuant to provisions in the new Senior Facilities, we may be required to obtain interest rate protection for up to 50% of our total indebtedness (including indebtedness of our subsidiaries). If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $1 million. This sensitivity analysis is based on our financial structure after giving effect to the incurrence of debt under the new Senior Facilities and assuming the only indebtedness outstanding under the Senior Facilities is under the term component thereof.

The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed by us. Our financial results can be significantly impacted as commodity prices fluctuate 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. The fixed-price physical contracts generally have terms of a year or more. We employ a policy of hedging gas production sold under NYMEX-based contracts by entering into NYMEX-based commodity derivative contracts with major financial institutions that we believe are of good credit standing. These contracts may take the form of swaps or options. In addition, we may sell NYMEX futures contracts. If NYMEX gas prices decreased $0.50 per Mcf, our gas sales revenues for the year ended December 31, 2003 would have decreased by $3.3 million, after considering the effects of the hedging contracts in place at December 31, 2003. We had no hedges or fixed price contracts on our oil production during 2003 or the first half of 2004. At September 30, 2004, we had hedges on a portion of our oil production for the remainder of 2004 through 2013. If the price of crude oil decreased $3.00 per Bbl, our oil sales revenues for the year ended December 31, 2003 would have decreased by $1.2 million. This sensitivity analysis is based on our 2003 oil and gas sales volumes and assumes the NYMEX gas price would be within the collars in 2004 listed in the table on page 59.

In connection with the Merger, we became a party to a long-term hedging arrangement with J. Aron. See “— Derivative Instruments.”

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” elsewhere in this prospectus for a more 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:

The accounting for and disclosure of oil and gas producing activities requires our 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.

Our proved developed and proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. We caution you that 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 oil and natural gas 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.

Our proved reserve information included in this prospectus is based on estimates prepared by independent petroleum engineers. Estimates prepared by others may be higher or lower than these estimates.

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 are 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.

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

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.

On January 1, 2001, we adopted SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. As a result of the adoption of SFAS 133, we recognize all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, 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).

Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss).

The relationship between the hedging instruments and the hedged items 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 on changes in the hedge’s intrinsic value. We consider these hedges 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. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. We measure effectiveness on at least a quarterly basis.

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. To manage our exposure to natural gas or oil price volatility, we have entered into NYMEX-based commodity derivative contracts, natural gas swaps and collars, and have designated the contracts for the special hedge accounting treatment permitted under SFAS 133.

Prior to January 1, 2001, under the deferral method, gains and losses from derivative instruments that qualified as hedges were deferred until the underlying hedged asset, liability or transaction monetized, matured or was otherwise recognized under generally accepted accounting principles. When recognized in net income (loss), hedge gains and losses were included as an adjustment to gas revenue or interest expense.

Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield service revenues are recognized when the goods or services have been provided.

We are required to recognize a liability for the fair value of our asset retirement obligations associated with our tangible, long-lived assets. The majority of the asset retirement obligations recorded by us relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties.

On January 1, 2003, we adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” to require us to recognize a liability for the fair value of our asset retirement obligations associated with our tangible, long-lived assets. The majority of the asset retirement obligations recorded by us relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $3.8 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.5 million, net of tax, as a cumulative effect of a change in accounting principle in our consolidated statement of operations in the first quarter of 2003.

Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma income from continuing operations for the years ended December 31, 2002 and 2001 was $4.3 million and $6.9 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million.

A reconciliation of our liability for asset retirement obligations for the year ended December 31, 2003 is as follows (in thousands):

On January 1, 2003, we adopted SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS 145 rescinds SFAS 4, “Reporting Gains and Losses from Extinguishment of Debt,” SFAS 44, “Accounting for Intangible Assets of Motor Carriers” and SFAS 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements” and amends SFAS No. 13, “Accounting for Leases.” Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in Accounting Principles Board Opinion No. (APB) 30, “Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” now will be used to classify those gains and losses. The adoption of SFAS 145 did not have any effect on our financial position, results of operations or cash flows.

In June 2002, the FASB issued SFAS 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 was effective for us for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on our financial position, results of operations or cash flows.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARE) 51.” FIN 46 is an interpretation of ARE 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 did not have any effect on our financial statement disclosures, financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for our financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on our financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS 150, “Accounting for Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer’s own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for our financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on our financial position, results of operations or cash flows.

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, we 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 Task Force 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 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. As we already include these assets as part of our capitalized oil and gas properties the application of this FSP will not have an impact on us. We had undeveloped leasehold costs of $5.1 million and $7.6 million at December 31, 2003 and 2002, respectively.

In December 2003, the FASB issued SFAS 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” an amendment of SFAS 87, 88, and 106, and a revision of

SFAS 132. This statement revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, Employers’ Accounting for Pensions, No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. This Statement retains the disclosure requirements contained in FASB Statement No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits, which it replaces. It requires additional disclosures to those in the original Statement 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. This Statement is effective for financial statements with fiscal years ending after December 15, 2003. The adoption of this standard did not have a material effect on our financial position, results of operations or cash flows.

At December 31, 2003, our total estimated proved reserves related to continuing operations were 355 Bcfe. Natural gas comprised approximately 90% of our estimated proved reserves, and 66% of our estimated proved reserves were classified as proved developed. Substantially all of our reserves are located in shallow, highly developed, blanket formations with long-lived, stable production profiles. At December 31, 2003 our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coal bed methane properties accounted for 38% and 10%, respectively.


	—	recent production and drilling results;

	—	reevaluation of our inventory of proved undeveloped well sites; and

	—	reevaluation of our estimated future development, completion and operating costs

Our evaluation is based on the preliminary information we have available. The reserve estimates at December 31, 2004 could be significantly different than the estimates provided above. The results of our evaluation could change after taking into account the impact of additional information we will gather subsequent to our preliminary review, the effect of the changes in prices for oil and natural gas which have occurred during the year, and other factors that will be considered in preparing the reserves estimates.

We expect to review this information with Wright & Company, Inc., independent petroleum consultants, in conjunction with the preparation of the reserves estimate as of December 31, 2004.

In the third quarter of 2004, we achieved average net production from continuing operations of approximately 47.3 Mmcfe per day from 4,084 gross (3,165 net) (at quarter end) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan. Based on our 2003 year end estimated proved reserves and third 2004 quarter average daily production, our properties have a reserve life of approximately 20 years.

At December 31, 2003, we operated approximately 3,400 wells, or 82% of our gross wells representing approximately 98% of the value of our estimated proved developed reserves on a PV-10 basis. We believe

We own and operate approximately 1,260 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets, including those in the northeastern United States. 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 NYMEX price 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.

The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations indicating the potential for oil and gas reservoirs to depths of 30,000 feet or more, oil and natural gas is currently produced primarily from shallow, highly developed, blanket formations at depths of 1,000 to 6,200 feet. Our drilling completion rates and those of others drilling in these shallow, highly developed, blanket formations historically have exceeded 90% with production generally lasting longer than 20 years.

We currently own working interests in 2,782 wells (2,450 net wells) in the Appalachian Basin, excluding our coalbed methane wells, which produced approximately 25 Mmcfe net per day for the quarter ending September 30, 2004. Most of our production in the Appalachian Basin is derived from the shallow (1,000 to 6,200 feet), blanket, Medina, Clinton and Clarendon formations, predominately in Pennsylvania and Ohio.

During 2003, we drilled 25 gross (24.0 net) development Medina wells and 15 gross (15.0 net) development Clarendon wells in Pennsylvania. We plan to continue this development drilling program by drilling 27 gross (26.4 net) Medina wells and 15 gross (15.0 net) Clarendon wells in 2004.

The Michigan Basin has geologic and operational similarities to the Appalachian Basin, geographic proximity to our operations in the Appalachian Basin and proximity to premium gas markets. Through our subsidiary, Ward Lake, we own working interests in 1,148 wells (561 net wells) in the Michigan Basin which produced approximately 19.6 Mmcfe net per day for the quarter ending September 30, 2004.

Most of our production in the Michigan Basin is derived from the shallow (700 to 2,000 feet), blanket, Antrim Shale formation. Completion rates for companies drilling to this formation have exceeded 90%, with production often lasting 20 years or more. The Michigan Basin also contains deeper formations with additional reserve potential. We have established production from certain of these deeper formations through our drilling operations. Because the production rate from Antrim Shale wells is relatively low, cost containment is a crucial aspect of our operations. Our operations in the Michigan Basin are more capital intensive than our Appalachian Basin operations because of the low natural reservoir pressures and the high initial water content of the Antrim Shale formation.

During 2003, we drilled 33 gross (29.2 net) wells to the Antrim Shale formation. We plan to drill 37 gross (31.6 net) in the Antrim Shale formation in 2004.

We own working interests in 154 producing coal bed methane wells in Pennsylvania and hold leases on approximately 73,000 net acres of prospective CBM properties. We own a 100% working interest in all of our CBM wells. These wells produced approximately 2.7 Mmcfe net per day for the quarter ending


	Focus on Exploiting and Developing Lower Cost, Lower Risk Reserves. We intend to focus our personnel and capital budget primarily on exploitation and development of our acreage in shallow, highly developed, blanket formations. Historically, our drilling completion rates and those of others drilling in these formations have exceeded 90%. We believe that this approach will substantially reduce many of the risks normally associated with oil and gas exploitation and development activities. We estimate that we have over 1,000 low-risk drilling locations across our properties, the majority of which are classified as proved undeveloped locations. In the second half of 2004, we plan to drill 59 low-risk development wells, representing approximately 95% of our remaining budget.

	Employ Long-Term, Fixed-Price Hedges To Protect Margins. We expect to manage commodity price risk by hedging substantial quantities of our expected production. We believe this approach has enhanced the predictability of our operating cash flow. To this end, we have become a party to a long-term hedging program with J. Aron, an affiliate of Goldman, Sachs & Co. We expect the hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves. In addition, we may enter into additional hedging transactions with respect to reserves we add in the future. See “Description of Other Indebtedness — Post-Merger Debt — The Hedges.”

	Realize Efficiencies In Unit Operating Costs. We strive to control our unit operating costs and improve our profit margins on production from existing and acquired properties through the application of advanced production technologies, operating efficiencies and mechanical improvements. We continually review our properties to determine what actions we can take to reduce operating costs and/or improve production. We strive to control field level costs through improved operating practices such as computerized production scheduling and the use of hand-held computers to gather field data. Actions that may be taken to improve production include modifying surface facilities, redesigning downhole equipment and recompleting existing wells. These actions can result in increased operating costs.

	Evaluate Potential Opportunistic Acquisitions. We may seek to opportunistically acquire properties in the Appalachian and Michigan Basins that complement our strategy and operations and provide additional exploitation and development opportunities.

Operations. We operate 82% of the wells in which we hold working interests. We seek to maximize the value of our properties through operating efficiencies associated with economies of scale and through operating cost reductions, advanced production technology, mechanical improvements and/or the use of deliverability enhancement techniques.

We maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, we review our properties to determine what action can be taken to control operating costs and/or improve production.

We own and operate approximately 1,260 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets.

Production, Sales Prices and Costs. The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the periods indicated, excluding


(1)	Average prices reflect the effect of hedges in effect during the periods indicated.

(2)	Operating margin (per Mcfe) is defined as average price less production expense and production taxes.

Our activities include exploitation and development drilling in the shallow, highly developed, blanket formations of the Appalachian and Michigan Basins. Our strategy is to develop lower risk wells with a high probability of success. We have an extensive inventory of acreage on which to conduct our exploitation and development activities.

In 2003, we drilled 79 gross (74.2 net) wells to shallow, highly developed, blanket formations in our operating areas at a net direct cost of approximately $15.7 million. We also drilled 19 gross (12.2 net) wells to less developed and deeper formations in 2003 at a net direct cost of approximately $18.2 million, including exploratory dry hole expense. The result of this drilling activity is shown in the table on page 71. These results include wells drilled on the TBR properties that were sold in June 2004.

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. For the remainder of 2004, we expect our drilling activity to focus primarily on shallow, highly developed, blanket formations. During the fourth quarter of 2004, we expect to spend approximately $5.5 million to drill approximately 32 gross (29.6 net) wells.

We believe that our post-Merger approach to our drilling activities will result in more consistent and predictable economic results than might be experienced with a higher risk drilling program.

In general, the highly developed, blanket formations found in the Appalachian and Michigan Basins are widespread in extent and hydrocarbon accumulations. Drilling completion rates of ours and others drilling these formations historically have exceeded 90%. The principal risk of such wells is uneconomic recoverable reserves.

We were a pioneer in CBM development and production in Pennsylvania, and we presently operate 154 coal bed methane gas wells in Indiana, Westmoreland and Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams.

In September 2001, we acquired our partner’s 40% working interest in the Blacklick CBM field, which gave us 100% ownership of this CBM project. With approximately 76,000 net CBM acres under lease in Pennsylvania, we believe that CBM will contribute significantly to our drilling portfolio. We plan to drill 18 gross (18.0 net) CBM wells in 2004.

The Antrim Shale formation, the principal shallow blanket formation in the Michigan Basin, is characterized by high formation water production in the early years of a well’s productive life with water production decreasing over time. Antrim Shale wells typically produce natural gas at rates of 75 Mcf to 125 Mcf per day for several years, with modest declines thereafter. Gas production often increases in the early years, as the producing formation becomes less water saturated. Average well lives are 20 years or more. We plan to drill 37 gross (31.6 net) wells to the Antrim Shale formation in 2004.

In addition to our CBM and Antrim drilling, we also plan to drill 27 gross (26.4 net) wells to the Medina formation and 15 gross (15.0 net) wells to the Clarendon formation in Pennsylvania during 2004.

Certain typical characteristics of our drilling programs in the shallow, highly developed, blanket formations we target are described below:

Drilling Results. The following table sets forth drilling results with respect to wells drilled by us during the past three years. These results include wells drilled on the TBR properties that were sold in June 2004.


(1)	Consists of wells drilled to the Berea and Clinton Sandstone formations in Ohio, the Clarendon, Upper Devonian, Coalbed Methane and Medina formations in Pennsylvania, the Medina Sandstone formation in New York and the Antrim Shale formation in Michigan.

(2)	Consists of wells drilled to the Trenton Black River Carbonates and Knox formations in Ohio, the Niagaran and Dundee Carbonates in Michigan, the Trenton Black River Carbonates, Oriskany Sandstone and Onondaga Limestone formations in Pennsylvania, and the Oriskany Sandstone, Onondaga Limestone, Trenton Black River Carbonates and Knox formations in New York.


(3)	Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. One additional well which was dry in the Trenton Black River formation was subsequently completed in the shallower Clinton formation.

We sold our interests, or rights to our interests, in the Trenton Black River assets. Following this disposition, we do not intend to have drilling operations in the deeper or less developed formations.

The following table sets forth our estimated proved oil and gas reserves as of December 31, 2001, 2002 and 2003 determined in accordance with the rules and regulations of the SEC. These estimates of proved reserves were prepared by Wright & Company, Inc., independent petroleum engineers. Proved reserves are the estimated quantities of oil and gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. Please read “Risk Factors — Information concerning our reserves and future net reserves is uncertain” and Note 16 to our Consolidated Financial Statements included elsewhere in this prospectus. These results include wells drilled on the TBR properties that were sold in June 2004.

The present value of the estimated future net cash flows before income taxes from our proved reserves as of December 31, 2003, determined in accordance with the rules and regulations of the SEC, was $597 million ($416 million after income taxes). Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2003 without escalation, except where changes in prices were fixed and readily determinable under existing contracts.

The following table sets forth the weighted average prices, including fixed price contracts, for oil and gas utilized in determining our proved reserves. We do not include our natural gas hedging financial instruments, consisting of natural gas swaps and collars, in the determination of our oil and gas reserves.

At December 31, 2003, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. Consequently, these may not reflect the prices actually received or expected to be received for oil and natural gas due to seasonal price fluctuations and other varying market conditions. The prices shown above are weighted average prices for the total reserves.


	—	recent production and drilling results;

	—	reevaluation of our inventory of proved undeveloped well sites; and

	—	reevaluation of our estimated future development, completion and operating costs

We expect to review this information with Wright & Company, Inc., independent petroleum consultants, in conjunction with the preparation of the reserves estimate as of December 31, 2004.

As described in Note 1 to the Consolidated Financial Statements, we evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In 2001, as a result of declining oil and natural and gas prices, we recorded an impairment of $1.4 million related to producing properties. No impairment was recorded in 2002. In 2003, we recorded impairments of $475,000 related to unproved properties and $421,000 related to producing properties. The impairments reduced the property’s book value to its estimated fair value.

As of December 31, 2003, we owned interests in 4,126 gross (3,155 net) producing oil and gas wells and operated approximately 3,400 wells, including wells operated for third parties. By operating a high percentage of our properties, we are able to control expenses, capital allocation and the timing of development activities in the areas in which we operate. In the third quarter of 2004, our average net production from continuing operations was approximately 47.3 Mmcfe per day consisting of approximately 41.2 Mmcf of natural gas and approximately 1,014 Bbls of oil per day.

The following table summarizes by state our productive wells at December 31, 2003:

The following table summarizes by state our gross and net developed and undeveloped leasehold acreage as of December 31, 2003. These numbers include acreage associated with the TBR properties that were sold in June 2004.

In 2003, we purchased reserves in certain wells we operate in Michigan for $3.8 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits, which we entered into in 1996. We had the option to purchase these properties beginning in 2003. We previously held a production payment on these properties including a 75% reversionary interest in certain future production. We purchased those reserve volumes beyond our currently held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf of proved developed producing gas reserves.

In 2002, we completed one acquisition transaction adding 4.2 Bcfe of proved developed reserves for a purchase price allocated to proved developed reserves of approximately $1.2 million. We previously held a production payment on these properties through December 31, 2002.

In 2001, we completed two acquisition transactions adding 1.9 Bcfe of proved developed reserves for a combined purchase price allocated to proved developed reserves of approximately $1.7 million. The primary transaction in 2001 was the purchase of the remaining 40% working interest in a CBM project giving us 100% ownership of the project.

We sold the Michigan assets of Arrow in May 2004. We sold the Ohio and Pennsylvania-related assets of Arrow in June 2004. On June 25, 2004, we completed the sale of the TBR assets to a third party. Both of these transactions were classified as discontinued operations. Historical information has been restated to remove the TBR properties and Arrow from continuing operations.

As a result of our decision to shift focus away from exploration and development activities in the Knox formation in Ohio, we sold substantially all of our undeveloped Knox acreage in Ohio, approximately 290,000 gross (272,000 net) acres, for approximately $2.8 million in September 2003. The sale resulted in a loss of approximately $150,000. We retained certain shallow development rights related to the Knox acreage.

On December 10, 2002, we sold 962 oil and natural gas wells in New York and Pennsylvania. The sale included substantially all of our Medina formation wells in New York and a smaller number of Pennsylvania Medina wells. The properties had approximately 23 Bcfe of total proved reserves. At the time of the sale, our net production from these wells was approximately 3.9 Mmcfe per day (4 Mcfe per day per well). We disposed of these properties due to the low production volume per well and high cost characteristics. The wells sold had proved developed reserves using SEC pricing parameters of approximately 19.4 Bcfe and proved undeveloped reserves of approximately 3.6 Bcfe. The sale resulted in proceeds of approximately $16.2 million. On December 10, 2002, we received $15.5 million in cash with the remaining amount of approximately $700,000 received in February 2003. The proceeds were used to pay down our revolving credit facility. As a result of the sale, we disposed of all of our properties producing from the New York Medina formation. As a result of the disposition of the entire New York Medina geographical/geological pool, we recorded a loss on the sale of $3.2 million ($1.8 million net of tax). According to Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of this group of wells is classified as discontinued operations. The loss on the sale of the New York Medina wells and the related results of these properties have been reclassified as discontinued operations for all periods presented.

During 2002, we completed the sale of six natural gas compressors in Michigan to a compression services company. The proceeds of approximately $2.0 million were used to pay down our existing credit facility. We also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors were relocated to maximize compression efficiency. A gain on the sale of $168,000 was deferred and amortized as rental expense over the life of the lease.

On August 1, 2002, we sold oil and gas properties consisting of 1,138 wells in Ohio that had approximately 10 Bcfe of reserves. At the time of the sale, our net production from these wells was approximately 3.1 Mmcfe per day (3 Mcfe per day per well). We disposed of these properties due to the low production volume per well and high operating costs per well. The proceeds of approximately $8.0 million were used to pay down our existing credit facility.

As of October 31, 2004, we had 180 full-time employees, including 155 oil and gas exploration and production employees and 25 general and administrative employees. Our management and technical staff in the categories above included eight petroleum engineers, two geologists and one geophysicist. We believe our relationship with our employees is generally good.

The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and undeveloped acreage and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end-users.

Our competitors in oil and gas exploration, development and production include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipeline companies and their affiliates. Many of these competitors possess and employ financial and personnel resources substantially in excess of those available to us. Such competitors may be able to pay more for desirable prospects or producing properties and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of ours will permit. Our ability to add to our reserves in the future will depend on the availability of capital, the ability to exploit our current developed and undeveloped lease holdings and the ability to select and acquire suitable producing properties and prospects for future exploration and development.

The only customer which accounted for 10% or more of our consolidated revenues during each of the years ended December 31, 2002 and 2001 was FirstEnergy Corp., sales to which amounted to $12.9 million and $21.0 million, respectively. During 2003, we had three customers that each accounted for 10% or more of consolidated revenues. The three customers were WPS Energy Services, Exelon Energy and National Fuel Gas with sales of $19.8 million, $11.5 million and $10.8 million, respectively.

Regulation of Production. In all states in which we are engaged in oil and gas exploration and production, our activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of oil and natural gas and other matters. Such regulations may impose restrictions on the production of oil and natural gas by limiting the number of wells or the location where wells may be drilled and by reducing the rate of flow from individual wells below their actual capacity to produce, which could adversely affect the amount or timing of our revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect our operations and financial condition.

Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and Federal Energy Regulatory Commission (“FERC”) regulations. In the past, the federal government has regulated the prices at which natural gas could be sold. Currently, sales by producers of natural gas can be made at uncontrolled market prices. Congress could, however, reenact price controls in the future.

Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. We cannot predict what further action the FERC will take on these matters. Some of the FERC’s more recent proposals may, however, adversely affect the availability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Environmental Regulations. Our oil and natural gas exploration, development, production and pipeline operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also referred to as the “U.S. EPA,” issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in

The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently may affect its profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly regulation could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we have not yet experienced any material adverse effect from compliance or non-compliance with these environmental requirements, there is no assurance that this trend will continue in the future.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a hazardous substance into the environment. These persons include the owner and/or operator of a disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the these hazardous substances for damages to natural resources and for the costs of certain health studies.

The Resource Conservation and Recovery Act, as amended, also known as “RCRA,” specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although the costs of managing these wastes generated by us may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure operations to prevent future contamination.

The federal Clean Air Act and analogous state laws restricts the emission of air pollutants from many sources, including equipment we use such as compressors to transport natural gas in our pipelines. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur costs in order to remain in compliance.

Our operations involve discharges to surface waters of fluids associated with the production of oil and gas. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of these fluids from oil and gas operations into state waters or waters of the United States prohibiting discharge, except in accord with the terms of a permit issued by U.S. EPA or the state. We hold several permits for the discharge of ground water that is produced in conjunction with our coal bed methane operations in Pennsylvania. These operations can produce substantial amounts of water as a byproduct when extracting gas. Our facilities in Michigan use injection wells to dispose of wastewater that

The Oil Pollution Act of 1990, as amended, also known as the “OPA,” pertains to the prevention of and response to spills or discharges of hazardous substances or oil into navigable water of the United States. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Regulations under the OPA and the Clean Water Act also require certain owners and operators of facilities that store or otherwise handle oil, such as ours, to prepare and implement spill prevention, control, and countermeasure, or “SPCC,” plans and spill response plans relating to possible discharges of oil into surface waters. The SPCC regulations were amended in 2002 and, currently, some plans may require revision by August 17, 2004 and implementation of any such revised plans by February 18, 2005. However, on June 17, 2004, the EPA proposed to extend these compliance dates by one year, to August 17, 2005 and February 18, 2006. We own and/or operate a substantial number of facilities that require SPCC plans or comparable plans under state law, and we are currently evaluating the extent of compliance by our facilities with SPCC regulations and comparable state requirements. We cannot assure you that costs that may be necessary for compliance with these SPCC and comparable state requirements will not be material.

In February 2000, four individuals filed a suit in the State of New York Supreme Court, Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. We believe the complaint is without merit and are defending the complaint vigorously. Although the outcome is still uncertain, we believe the action will not have a material adverse effect on our financial position, results of operations or cash flows. We no longer own the wells that were subject to the suit.

In April 2002, we were notified of a claim by an overriding royalty interest 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 operation or cash flows.

We were audited by the state of West Virginia for the years 1996 through 1998. The state assessed taxes which we have contested and filed a petition for reassessment. In February 2003, we were notified by the State Tax Commissioner of West Virginia that our petition for reassessment had been denied and taxes due, plus accrued interest, are now payable. We disagreed with the decision and appealed. In April 2004, we received a favorable ruling on our appeal and now expect to receive a refund of approximately $500,000. The state has chosen not to appeal the ruling.

We are involved in several lawsuits arising in the ordinary course of business. We believe that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows.

Our executive officers and directors and their respective positions and ages are set forth below:

All of our executive officers serve at the pleasure of our Board of Directors. None of our executive officers is related to any other executive officer or director. The Board of Directors consists of six members, each of whom is elected annually to serve one-year terms. The business experience of each executive officer and director is summarized below.

James A. Winne III. On December 16, 2004, Mr. Winne was appointed Chief Executive Officer and Chairman of our Board of Directors. Prior to that he served as Senior Vice President since his appointment on November 1, 2004. Mr. Winne has been a director since November 1, 2004. Mr. Winne is President, Chief Executive Officer and a member of the Board of Supervisors of Legend Natural Gas, LP and Legend Natural Gas II, LP (collectively, “Legend”), each a privately held oil and gas company located in Houston, Texas. He has over 25 years of experience in the oil and gas industry. Prior to joining Legend in 2001, he served as President and Chief Executive Officer of North Central Oil Corporation from 1993 to 2001. Mr. Winne attended the University of Houston and is a Registered Land Professional. He serves on the Board of Directors of PI Corporation, Windward Oil and Gas Corporation, Encore Acquisition Company and Mariner Energy, Inc., all of which are oil and gas companies. Legend and Mariner Energy, Inc. are affiliates of Carlyle/Riverstone.

Michael Becci. On December 16, 2004, Mr. Becci was appointed President and Chief Operating Officer. Prior to that he served as Senior Vice President since his appointment on November 1, 2004. Mr. Becci has been a director since November 1, 2004. Mr. Becci is Vice President, Chief Financial Officer and a member of the Board of Supervisors of Legend. Previously, he served as Vice President and Chief Financial Officer of North Central Oil Corporation from 1990 to 2001. He is a Certified Public Accountant with over 20 years of experience in the oil and gas industry. Mr. Becci holds a Bachelor of Science degree in Business Administration from Valparaiso University. He is a Director of PI Corporation and Windward Oil and Gas Corporation. Legend is an affiliate of Carlyle/Riverstone.

R. Mark Hackett. Mr. Hackett has been our Senior Vice President of Geoscience and Engineering since December of 2003. He has over 15 years of experience in drilling, engineering and producing operations in the Appalachian Basin. Prior to joining us, Mr. Hackett held various positions at Columbia Natural Resources, Inc. from 1997 to 2003, including Vice President of Operations. From 1988 to 1997, he was employed by Alamco, Inc., where he last held the position of Vice President of Engineering.

Richard R. Hoffman. Mr. Hoffman has been our Senior Vice President of Operations since December of 2003. Previously, he served as Senior Vice President of Exploration and Production since March of 2001. Mr. Hoffman has worked in the oil and gas industry for 31 years and has extensive operational experience in the Appalachian Basin. From 1998 to 2000, he served as Manager of Production for Dominion Appalachian Development Inc., a subsidiary of Dominion Resources, Inc., specializing in natural gas exploration and production. From 1982 to 1997, he was Executive Vice President and Chief Operating Officer of Alamco, Inc., and served on its Board of Directors from 1988 to 1997. He is affiliated with numerous oil and gas associations including the Ohio Oil and Gas Association, the West Virginia Oil and Natural Gas Association and the Independent Oil and Gas Association of West Virginia where he served as a Director from 1995 to 1997. He is also a member of the Society of Petroleum Engineers.

Robert W. Peshek. Mr. Peshek has been our Senior Vice President since December of 2003. Previously, he served as Vice President of Finance since 1997 and in 1999 was appointed Chief Financial Officer. Prior to that, he served as Corporate Controller and Tax Manager from 1994 to 1997. His professional affiliations include the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is a member of the Ohio Oil and Gas Association.

David M. Becker. Mr. Becker has been our Vice President since May of 2000. He is also President and Chief Operating Officer of Ward Lake Drilling, Inc., one of our wholly owned subsidiaries, and General Manager of the Michigan Exploration and Production District since 1995. His professional affiliations include the Michigan Oil and Gas Association and the American Petroleum Institute.

Duane D. Clark. Mr. Clark has been our Vice President of Legal Affairs/ Gas Marketing since April 2001. Previously, he served as Vice President of Gas Marketing. His professional affiliations include the Ohio Oil and Gas Association and the Pennsylvania Oil and Gas Association.

Patricia A. Harcourt. Ms. Harcourt has been our Vice President of Administration since January 2003. Previously she served as Director of Administration from 2001 to 2003 and Director of Corporate Communications from 1994 to 2001. She joined us in 1988 as Investor Relations Coordinator. Prior to joining us, Ms. Harcourt was employed by Austin Powder Company as Employee Relations Administrator. She has 16 years of experience in the oil and gas industry and is a member of the Ohio Oil and Gas Association. Ms. Harcourt is also a member of the National Investor Relations Institute and the Society for Human Resource Management.

Frederick J. Stair. Mr. Stair has been our Vice President and Corporate Controller since January 2003 and 1997, respectively. Prior to that date he served as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 23 years of accounting experience in the oil and gas industry. Mr. Stair is a member of the Petroleum Accountants Society of Appalachia.

Gregory A. Beard. In July 2004, Mr. Beard was elected to our Board of Directors. Mr. Beard is a Principal with Riverstone Holdings, LLC and has been with the firm since 2000. Prior to joining Riverstone, Mr. Beard was an Associate with Asen and Company, a privately held investment firm, from 1997 to 2000, and was associated with a Nashville, Tennessee-based investment firm from 1995 to 1997. Mr. Beard began his career as a Financial Analyst at Goldman Sachs in 1993. Mr. Beard currently serves as a director of Legend Natural Gas, LP, InTank, Inc., Capital C Energy, LLC, Mariner Energy, Inc. and CDM Resource Management, Ltd.

Michael B. Hoffman. In July 2004, Mr. Hoffman was elected to the Board of Directors. Mr. Hoffman is a Managing Director of Riverstone Holdings, LLC, and serves on the Managing Committee responsible for all portfolio activities. Prior to joining Riverstone, Mr. Hoffman was Senior Managing Director and Head of the Mergers & Acquisitions Advisory Group at The Blackstone Group. He was also a member of Blackstone’s Management, Executive and Investment Committees. Before joining Blackstone in 1989, Mr. Hoffman was the Partner in charge of the Merger & Acquisitions Department of Smith Barney, Harris Upham & Co. Mr. Hoffman currently serves as a director of Buckeye Pipe Line Company LLC, the general partner of Buckeye Partners, L.P. Capital C Energy, LLC,

Pierre F. Lapeyre, Jr. In July 2004, Mr. Lapeyre was elected to our Board of Directors. Mr. Lapeyre is a Founder and Managing Director of Riverstone Holdings, LLC, a private equity fund, and serves on its Managing Committee responsible for all portfolio activities. Prior to founding Riverstone in May 2000, Mr. Lapeyre served as a Managing Director of Goldman Sachs in its Global Energy and Power Group since 1996. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year investment banking career focused on the energy and power sectors. Mr. Lapeyre currently serves on the boards of Legend Natural Gas LP, Topaz Power Group, LLC, Magellan GP, LLC, the general partner of Magellan Midstream Partners, LP, Seabulk International, Inc., CDM Resource Management, Ltd., Capital C Energy, LLC, Mariner Energy, Inc. and InTank, Inc.

David M. Leuschen. In July 2004, Mr. Leuschen was elected to our Board of Directors. Mr. Leuschen is a Founder and Managing Director of Riverstone Holdings, LLC and serves on its Managing Committee and is responsible for all portfolio activities. Prior to founding Riverstone in May 2000, Mr. Leuschen spent 22 years with Goldman Sachs. He joined the firm in 1977, established their Global Energy and Power Group in 1982, became a Partner in 1986, and remained a Partner with the firm until leaving to found Riverstone in 2000. Mr. Leuschen currently serves as a director of Seabulk International Inc., Frontier Drilling ASA, Legend Natural Gas LP, InTank, Inc., Buckeye Pipe Line Company LLC, the general partner of Buckeye Partners, L.P., Capital C Energy, LLC, Mariner Energy, Inc. and Mega Energy LLC, as well as a number of other industry-related businesses and nonprofit Boards of Directors. He is also owner and President of Switchback Ranch LLC, an integrated cattle ranching operation in the western United States.

Our Board of Directors recently established our Audit Committee, which is composed of non-executive officer directors. The primary purpose of the Audit Committee will be to assist the Board of Directors’ oversight of (i) the integrity of the our financial statements, (ii) our compliance with legal and regulatory requirements, (iii) our independent auditor’s qualifications and independence and (iv) the performance of our internal audit function and independent auditors. The Audit Committee is solely responsible for the appointment and compensation of our independent auditors. The Audit Committee operates under a written charter adopted and approved by the Board of Directors.

The Audit Committee will meet periodically with our independent registered public accountants, Ernst & Young, LLP and representatives of our internal audit staff and management to review financial statements and the results of audit activities.

The following table shows our annual and long-term compensation for services in all capacities during the fiscal years ended December 31, 2003, 2002 and 2001 of our Chief Executive Officer and our other four most highly compensated executive officers.


(1)	Represents contributions of cash and common stock to our 401(k) Plan for the account of the named executive officer.

(2)	Effective at the completion of the Merger, Frost W. Cochran replaced Mr. Schwager as our President and Chief Executive Officer. Mr. Cochran’s compensation was included in the management services fee paid to Capital C. See “Certain Relationships and Related Transactions.” On December 16, 2004 Mr. Cochran resigned as our President and Chief Executive Officer. Effective December 16, 2004 James A. Winne III replaced Mr. Cochran as Chief Executive Officer.

(3)	This consists of an annual performance bonus of $210,000 and an annual retention bonus of $330,000 paid to Mr. Schwager on June 30, 2003. For financial statement purposes, we have accrued an additional retention bonus of $165,000 for the period July 1, 2003 through December 31, 2003.

(4)	Mr. Hoffman joined us in March 2001.

(5)	Includes moving expenses of $41,373.

(6)	Mr. Lay was not an Executive Officer as of December 31, 2003, as he moved into an operations role.


(1)	Effective at the completion of the Merger, Frost W. Cochran replaced Mr. Schwager as our President and Chief Executive Officer. On December 16, 2004 Mr. Cochran resigned as our President and Chief Executive Officer. Effective December 16, 2004 James A. Winne III replaced Mr. Cochran as Chief Executive Officer.

We were a party to a management services agreement with Capital C, pursuant to which officers of Capital C provided certain management and advisory services to us for a quarterly fee of $250,000. These services included 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 was terminated effective December 20, 2004.

We have agreed to reimburse Legend Natural Gas II, LP for actual expenses incurred by its personnel in connection with the provision of certain past and future services for our benefit, the amount of which could exceed $60,000. As is more fully described under “Management and Directors” on page 82, James A. Winne III and Michael Becci are executive officers, members of the Board of Supervisors and limited partners of Legend Natural Gas II, LP, which is an affiliate of Carlyle/Riverstone.

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

The Notes are secured by a second-priority security interest in and continuing lien on our and each of the Guarantor’s (as defined in “Description of the Notes — Certain Definitions”) (each, a “Grantor”) right, title and interest in the applicable Grantor’s real and personal property (collectively, the “Collateral”) other than Excluded Assets (as defined in “Description of the Notes — Certain Definitions”), in each case, whether now owned or existing or hereafter acquired and wherever located, consisting of proved producing reserves constituting a substantial majority of the aggregate value of our proved producing reserves on a PV-10 basis (provided that, due to the large number of properties, not all of the mortgages on such properties and leasehold interests may be in place at the time of the exchange offer) and substantially all of our other property (other than Hydrocarbon Properties) consisting of property of the Grantors whether owned or leased, accounts, oil and natural gas as extracted from our properties, general intangibles, goods, insurance, intellectual property, investment related property, money, receivables, agreements of each Grantor relating to the disposition of hydrocarbons, interests in hydrocarbons (including, without limitation, oil and gas in tanks and all rents, issues, profits, proceeds, products and revenues) and rights in connection with the purchasing of any interests and estates in any minerals, including hydrocarbons. The Collateral also includes a pledge of the stock of each domestic subsidiary owned by us or any of the Guarantors and a pledge of our stock owned by Capital C. We may merge one or more of the Guarantors into Belden & Blake Corporation prior to December 31, 2004.

The Collateral does not include certain wells in New York and does not include undeveloped acreage. To the extent a Grantor develops such undeveloped acreage and such acreage is producing in commercial quantities, the indenture requires such Grantor to then provide a mortgage over such properties (subject to the second-priority nature of the security interest).

Our Senior Facilities are 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 for letters of credit to collateralize the Hedges and other hedging transactions; 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 hedging transactions. The Senior Facilities are secured by a first-priority lien on certain of our assets and those of any guarantor subsidiaries subject to permitted liens and excluded assets to be agreed. See “Description of the Collateral.”

The Term Facility consists of a $100 million term loan that was made on July 7, 2004. Proceeds of the term loan were used to fund a portion of the equity consideration in the Merger, to refinance our existing indebtedness, and to pay expenses associated with the transactions.

All or a portion of the term loan will bear interest, at our option, either at the Base Rate or at the Eurodollar Rate plus, in each case, a specified margin subject to adjustment. The Base Rate is a rate calculated daily as the highest of (i) the annual rate of interest quoted in The Wall Street Journal, Money Rates Section as the Prime Rate (currently defined as the base rate on corporate loans posted by at least 75% of the nation’s thirty (30) largest banks), and (ii) the federal funds effective rate plus 1/2 of 1%. Interest on any portion of the term loan bearing interest based on the Base Rate is payable quarterly on March 31, June 30, September 30, and December 31 of each year.

The Eurodollar Rate is equal to the London Interbank Offered Rate as adjusted for certain regulatory reserve costs. At our election, interest periods for that portion of the term loan bearing interest at the Eurodollar Rate may be one, two, three and six months. Interest on any portion of the term loan bearing interest based on the Eurodollar Rate is payable at the end of each interest period, and if an interest period is longer than three months, every three months during the interest period. Interest on overdue term loan amounts accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%.

The term loan amortizes quarterly at the rate of 0.25% of the outstanding amount of the Term Loan during the first six years, with the balance payable in equal quarterly installments during the seventh year. The term loan is required to be paid in full on July 7, 2011. We are entitled to voluntarily prepay the term loan at any time, in whole or in part, without premium or penalty.

We must make mandatory prepayments of the term loan utilizing funds derived from certain proceeds as follows: (i) 100% of the net cash proceeds of the sale or disposition of our property and assets and that of our subsidiaries (other than net cash proceeds of sales or dispositions of inventory in the ordinary course of business and net cash proceeds less than a specified amount that are reinvested in other assets useful in our business within 360 days); (ii) 100% of the net cash proceeds of insurance paid on account of any loss by us or our subsidiaries of any property or assets, other than net cash proceeds less than a specified amount that are reinvested in other assets useful in our business or that of our subsidiaries (or used to replace damaged or destroyed assets) within 360 days of receipt thereof; (iii) 50% of the net cash proceeds received from the issuance of equity securities by us or our subsidiaries (other than issuances pursuant to employee stock plans); (iv) 100% of the net cash proceeds received from the incurrence of indebtedness by us or our subsidiaries (other than indebtedness otherwise permitted under the documentation for the Senior Facilities), payable no later than the first business day following the date of receipt; and (v) 100% (subject to reduction if certain financial performance measures are obtained) of “excess cash flow” payable within 105 days of fiscal year end. Mandatory prepayments are applied to scheduled amortization payments on the term loan on a pro rata basis.

The Revolving Facility is a $30 million revolving credit facility that may be utilized by us for revolving loans, letters of credit and letters of credit to secure the Hedges and other hedging transactions. Revolving loans may be borrowed anytime beginning July 7, 2004 and ending on July 7, 2010. Proceeds of the revolving loan may be used for ongoing working capital requirements and general corporate purposes and up to $15 million for the issuance of letters of credit (in addition to the letters of credit provided under the letter of credit facility described below) to provide credit support for our obligations under the Hedge Agreement and other hedging transactions. An additional $5 million of letters of credit may be obtained during the term of the Revolving Facility for general corporate purposes.

All or a portion of the revolving loans will bear interest, at our option, either at the Base Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment or at the Eurodollar Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment. Interest payment dates for revolving loans bearing interest based on the Base Rate and revolving loans bearing interest at the Eurodollar Rate are the same as interest payment dates for the term loan (as discussed above). Interest on overdue revolving loan amounts accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%.

Letters of credit issued under the revolving facility accrue fees equal to a specified rate per annum on the average daily maximum amount available to be drawn under such letters of credit. Letter of credit fees are payable quarterly in arrears on March 31, June 30, September 30, and December 31 of each year. In addition, a fronting fee on the average daily maximum amount available to be drawn under such letters of credit will be payable to the issuing bank for each letter of credit.

We are required to pay a commitment fee equal to 0.50% per annum times the daily average undrawn portion of the revolving facility (reduced by the amount of letters of credit issued and outstanding under the revolving facility) which shall accrue from July 7, 2004 and shall be payable quarterly in arrears on March 31, June 30, September 30, and December 31 of each year.

The revolving loan does not amortize. The revolving loan is required to be paid in full on July 7, 2010. We are entitled to voluntarily prepay the revolving loan at any time, in whole or in part, without premium or penalty. Any portion of the revolving loan that is prepaid may be reborrowed. Once the term loan has been repaid in full, we must make mandatory prepayments of the revolving loan on the same basis as described above in the discussion of the term loan.

The Letter of Credit Facility provides for the issuance of up to $40 million of letters of credit. Letters of credit under the Letter of Credit Facility may be obtained any time beginning on July 7, 2004 and ending on July 7, 2010. These letters of credit may be used only to provide credit support for our obligations under the Hedge Agreement and other hedging transactions.

Letters of credit issued under the Letter of Credit Facility accrue fees equal to a specified rate per annum on the average daily maximum amount available to be drawn under such letters of credit. These letter of credit fees are payable quarterly in arrears on March 31, June 30, September 30, and December 31 of each year. In addition, a fronting fee on the average daily maximum amount available to be drawn under such letters of credit will be payable to the issuing bank for each letter of credit.

We are required to pay an annual commitment fee based upon the daily average undrawn portion of the Letter of Credit Facility (reduced by the amount of letters of credit issued and outstanding under the Letter of Credit Facility) which shall accrue from July 7, 2004 and shall be payable quarterly in arrears on March 31, June 30, September 30, and December 31 of each year.

Once the term loan and the revolving loan has been repaid in full, we must apply amounts that would otherwise be mandatory prepayments to cash collateralize our obligations to the lenders under the letters of credit.

Each of our existing and subsequently acquired domestic (and, to the extent no material adverse tax consequences would result, foreign) subsidiaries (other than Immaterial Subsidiaries) will guarantee all obligations under the Senior Facilities.

The Senior Facilities, each guaranty and any interest rate hedging obligations that we or our subsidiaries have entered into with a lender or our affiliates are secured by first-priority security interests in certain of our assets and those of our subsidiaries, subject to permitted liens. This security includes a first-priority security interest in all of our capital stock and all capital stock of each of our domestic subsidiaries (other than Immaterial Subsidiaries) and all intercompany debt. See “Description of the Collateral.”

Our obligations under the Hedge Agreement, to the extent not secured by cash or letters of credit, are secured by second-priority security interests in the assets securing the senior facilities. The Notes are secured by second-priority security interests in the assets securing the Senior Facilities and the Hedge Agreement. The priority of the security interests and related creditor rights with respect to the Senior Facilities, the Hedge Agreement, and the Notes are described in the intercreditor agreement.

Our new Senior Facilities contain customary affirmative and negative covenants for senior financings of this kind including:


	•	a covenant requiring us within 120 days after the date of closing the Merger to obtain interest rate protection through interest rate swaps, caps or other agreements against increases in the interest rates with respect to a notional amount of indebtedness such that, not less than 50% of the total indebtedness of us and our subsidiaries outstanding as of the date of the Merger is either (i) subject to such interest rate protection agreements or (ii) fixed rate indebtedness, in each case for a period of not less than three years;

	•	a minimum interest coverage covenant;

	•	a capital expenditures covenant;

	•	a maximum total first-priority senior leverage ratio covenant;

	•	a covenant imposing limitations on exploration and drilling capital expenditures (other than in connection with proved undeveloped reserves);

	•	a covenant imposing maximum total leverage to PV-10 of our total proved reserves;

	•	a covenant imposing a limitation on our indebtedness;

	•	a covenant imposing limitations on liens; and

	•	a covenant imposing limitations on restricted payments.


	•	failure to make payments when due;

	•	defaults under the Hedge Agreement;

	•	defaults under other agreements or instruments of indebtedness;

	•	noncompliance with covenants;


	•	breaches of representations and warranties;

	•	bankruptcy;

	•	judgments in excess of a specified amount;

	•	ERISA defaults;

	•	impairment of security interests in collateral;

	•	invalidity of guarantees; and

	•	“change of control.”

On July 7, 2004, we became a party to the Hedges with J. Aron pursuant to the Hedge Agreement. We have agreed to maintain these Hedges with J. Aron or its successor or permitted assigns. We anticipate that the Hedges will cover approximately 62% of the expected production through 2013 from our current estimated proved reserves and will range from 52% to 84% of such expected production in any year. The Hedges primarily take the form of monthly settled fixed price swaps in respect of the settlement prices for the market standard NYMEX futures contracts on crude oil and natural gas. Under such transactions, we pay NYMEX-based floating price per Mmbtu, in the case of Hedges on natural gas, and we pay a NYMEX-based floating price per Bbl, in the case of Hedges on crude oil, for each month during the term of the Hedges and receive a fixed price per Mmbtu or Bbl (as the case may be) according to a monthly schedule of fixed prices that we established upon completion of the Merger. The transactions will be settled on a net basis. The notional amounts of the Hedges are designed to provide sufficient hedged cash flow to cover operating expenditures, general and administrative expenses, interest expenses and the majority of capital expenditures needed to develop proved reserves.

We are required to cause the Hedge Agreement to remain in effect for so long as any portion of the Senior Facilities or the Notes remains outstanding. The Hedges are documented under a standard ISDA agreement with customized credit terms, designed to mitigate the liquidity pressures in a high commodity price environment. The initial collateral requirements and ongoing margin requirements (based on market movements) are satisfied by letters of credit issued under the Senior Facilities, with an aggregate capitalization of $55 million. To support any exposure in excess of amounts supported by the letters of credit, we have granted J. Aron a second lien on the same assets that secure the Senior Facilities and the Notes and, to the extent our obligations exceed such letters of credit, such obligations are secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes and are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes on a second-priority senior secured basis. We may enter into crude oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by the letters of credit issued under the Senior Facilities and by a second-priority lien on the same assets securing the Senior Facilities and the Notes.

You can find the definitions of certain terms used in this description under the subheading “Certain Definitions.” In this description, the word “Company” refers only to Belden & Blake Corporation and not to any of its subsidiaries. The term “Notes” refers to both the New Notes and the Outstanding Notes.

The Company will issue the New Notes under an indenture among itself, the Guarantors and BNY Midwest Trust Company, as trustee, in a private transaction that is not subject to the registration requirements of the Securities Act of 1933. See “Notice to Investors.” The terms of the New Notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended. The security documents and the collateral trust agreement referred to below under the caption “— Security” contain the terms of the security interests that will secure the Notes.

The following description is a summary of the material provisions of the indenture, the collateral trust agreement and the security documents. It does not restate those agreements in their entirety. We urge you to read these agreements because they, and not this description, define your rights as holders of the Notes. Copies of these agreements are available as set forth below under “— Additional Information.” Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture.

The registered holder of a Note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.


	•	are general obligations of the Company;

	•	are secured on a second-priority basis, equally and ratably with all obligations of the Company under the Hedge Agreement and any future Parity Lien Debt, by Liens on certain of the assets of the Company other than the Excluded Assets, subject to the liens securing the Company’s obligations under the Credit Agreement and any other Priority Lien Debt and other Permitted Prior Liens;

	•	are effectively junior, to the extent of the value of the Collateral, to the Company’s obligations under the Credit Agreement and any other Priority Lien Debt, which will be secured on a first-priority basis by the same assets of the Company that secure the Notes;

	•	are effectively junior to any Permitted Prior Liens, to the extent of the value of the assets of the Company subject to those Permitted Prior Liens;

	•	are pari passu in right of payment with all other senior indebtedness of the Company, including Indebtedness under the Credit Agreement and the Hedge Agreement;

	•	are senior in right of payment to any future subordinated Indebtedness of the Company, if any; and

	•	are guaranteed by the Guarantors.

The Notes will be guaranteed by each of the Company’s current or future Domestic Subsidiaries (other than Immaterial Subsidiaries) that guarantees any Priority Lien Debt or obligations under the Hedge Agreement.


	•	are secured on a second-priority basis, equally and ratably with all obligations of that Guarantor with respect to its guarantee of obligations under the Hedge Agreement and any other future Parity Lien Debt, by Liens on certain of the assets of that Guarantor other than the Excluded Assets, subject to the liens securing that Guarantor’s guarantee of the Credit Agreement and any other Priority Lien Debt and other Permitted Prior Liens;

	•	are effectively junior, to the extent of the value of the Collateral, to that Guarantor’s guarantee of the Credit Agreement and any other Priority Lien Debt, which will be secured on a first-priority basis by the same assets of that Guarantor that secure the Notes;

	•	are effectively junior to any Permitted Prior Liens, to the extent of the value of the assets of that Guarantor subject to those Permitted Prior Liens;

	•	are pari passu in right of payment with all other senior indebtedness of that Guarantor, including its guarantee of Indebtedness under the Credit Agreement and the Hedge Agreement; and

	•	are senior in right of payment to any future subordinated Indebtedness of that Guarantor, if any.

Pursuant to the indenture, the Company is permitted to designate additional Indebtedness as Priority Lien Debt, subject to the Priority Lien Cap. The Company is also permitted to incur additional Indebtedness as Parity Lien Debt subject to the covenants described below under “Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and “Covenants — Liens.” As of September 30, 2004, after giving pro forma effect to this offering and the incurrence of the Indebtedness under the Credit Agreement and the Hedge Agreement and the use of the net proceeds herefrom and therefrom, as described in “Use of Proceeds,” the Notes would have been junior to approximately $155 million of Priority Lien Debt outstanding under the Senior Facilities. These obligations include $55 million aggregate amount of letters of credit issued under the Senior Facilities. After giving effect to the application of the net proceeds from the offering of the Outstanding Notes, the Company is also able to incur in the future $15 million of borrowings under the revolving credit facility under the Credit Agreement. The amount of the Obligations under the Hedge Agreement will likely vary on a daily basis.

As of the date of the indenture, all of our Subsidiaries are “Restricted Subsidiaries.” However, under the circumstances described below under the caption “— Certain Covenants — Designation of Restricted and Unrestricted Subsidiaries,” we are permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the Notes.

The Company issued the Outstanding Notes in an aggregate principal amount of $192.5 million. The Company may issue additional Notes (the “Additional Notes”) under the indenture from time to time after this exchange offer. Any issuance of Additional Notes is subject to all of the covenants in the indenture, including the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The Notes and any Additional Notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Company will issue Notes in denominations of $2,000 and integral multiples of $1,000. The Notes will mature on July 15, 2012.

Interest on the Notes will accrue at the rate of 8.75% per annum and will be payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2005. Interest on overdue principal and interest and Special Interest, if any, will accrue at a rate that is 1% higher than the then applicable interest rate on the Notes. The Company will make each interest payment to the holders of record on the immediately preceding January 1 and July 1.

Interest on the Notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

If a holder of Notes has given wire transfer instructions to the Company, the Company will pay all principal, interest and premium and Special Interest, if any, on that holder’s Notes in accordance with those instructions. All other payments on the Notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless the Company elects to make interest payments by check mailed to the holders of the Notes at their address set forth in the register of holders.

The trustee will initially act as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Subsidiaries may act as paying agent or registrar.

A holder may transfer or exchange Notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes. Holders will be required to pay all taxes due on transfer. The Company will not be required to transfer or exchange any Note selected for redemption. Also, the Company will not be required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The Notes will be guaranteed by each of the Company’s current and future Domestic Subsidiaries (other than Immaterial Subsidiaries) that guarantees any Priority Lien Debt or the Hedge Agreement. These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors — A subsidiary guarantee and the liens securing a guarantee could be voided if it constitutes a fraudulent transfer under the Bankruptcy Code or similar state law.” We may merge one or more of the Guarantors into Belden & Blake Corporation prior to December 31, 2004.

Each Note Guarantee will be secured by a security interest in certain of the assets of the Guarantor, other than the Excluded Assets, on a second-priority basis, equally and ratably with the guarantees of that Guarantor of the obligations under the Hedge Agreement and any other Parity Lien Debt, subject to the Liens securing the guarantees of that Guarantor of the Credit Agreement and any other Priority Lien Debt and other Permitted Prior Liens.

A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate with or merge with or into (whether or not such Guarantor is the surviving Person) another Person, other than the Company or another Guarantor, unless:


	(1) immediately after giving effect to that transaction, no Default or Event of Default exists; and

	(2) either:


	(a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the obligations of that Guarantor under the indenture, its Note Guarantee and the exchange and registration rights agreement pursuant to a supplemental indenture and appropriate security documents satisfactory to the trustee; or


	(b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the indenture.


	(1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sale” provisions of the indenture;

	(2) in connection with any sale or other disposition of all of the Capital Stock of that Guarantor to a Person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, if the sale or other disposition does not violate the “Asset Sale” provisions of the indenture;

	(3) if the Company designates any Restricted Subsidiary that is a Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

	(4) if that Guarantor is released from its Guarantee of Priority Lien Debt and the Hedge Agreement; provided, however, that if, at any time following such release, that Guarantor provides a Guarantee of any Priority Lien Debt or the Hedge Agreement, then such Guarantor shall be required to provide a Note Guarantee at such time; or

	(5) upon Legal Defeasance or Covenant Defeasance or satisfaction and discharge of the indenture as provided below under the captions “— Legal Defeasance and Covenant Defeasance” and “— Satisfaction and Discharge.”

The obligations of the Company with respect to the Notes, the obligations of the Guarantors under the guarantees, the obligations of the Company under the Hedge Agreement, the obligations of the Guarantors under the guarantees of the obligations under the Hedge Agreement and all other Parity Lien Obligations and the performance of all other obligations of the Company, the Guarantors and the Company’s other Restricted Subsidiaries under the Note Documents and the Hedge Agreement are secured equally and ratably by second-priority Liens in the Collateral granted to the collateral trustee for the benefit of the holders of the Parity Lien Obligations. These Liens are junior in priority to the Liens securing the Priority Lien Obligations and to all other Permitted Prior Liens. The Liens securing the Priority Lien Obligations are also held by the collateral trustee. See “Description of the Collateral.”

On the date of the indenture, the Company and the other Pledgors entered into a collateral trust agreement with the collateral trustee and each other Secured Debt Representative. The collateral trust agreement sets forth the terms on which the collateral trustee receives, holds, administers, maintains, enforces and distributes the proceeds of all Liens upon any property of the Company or any other Pledgor at any time held by it, in trust for the benefit of the present and future holders of the Secured Obligations.

Wells Fargo Bank, N.A. has been appointed pursuant to the collateral trust agreement to serve as the collateral trustee for the benefit of:


	•	the holders of the Notes;

	•	the creditors in respect of Indebtedness arising under the Hedge Agreement;


	•	the holders of all other Parity Lien Obligations outstanding from time to time; and

	•	the holders of all Priority Lien Obligations outstanding from time to time.

The collateral trust agreement provides that the collateral trustee may not be the same institution serving as a Parity Lien Representative or a Priority Lien Representative, but any Priority Lien Representative may serve as an agent for the collateral trustee.

The collateral trustee holds (directly or through co-trustees or agents), and is entitled to enforce, all Liens on the Collateral created by the security documents.

Except as provided in the collateral trust agreement or as directed by an Act of Required Creditors in accordance with the collateral trust agreement, the collateral trustee is not obligated:


	(1) to act upon directions purported to be delivered to it by any Person;

	(2) to foreclose upon or otherwise enforce any Lien; or

	(3) to take any other action whatsoever with regard to any or all of the security documents, the Liens created thereby or the Collateral.

The Company has delivered to each Secured Debt Representative copies of all security documents delivered to the collateral trustee.

If the collateral trustee at any time receives written notice that any event has occurred that constitutes a default under any Secured Debt Document entitling the collateral trustee to foreclose upon, collect or otherwise enforce its Liens thereunder, it will promptly deliver written notice thereof to each Secured Debt Representative. Thereafter, the collateral trustee may await direction by an Act of Required Creditors and will act, or decline to act, as directed by an Act of Required Creditors, in the exercise and enforcement of the collateral trustee’s interests, rights, powers and remedies in respect of the Collateral or under the security documents or applicable law and, following the initiation of such exercise of remedies, the collateral trustee will act, or decline to act, with respect to the manner of such exercise of remedies as directed by an Act of Required Creditors. Other than following a bankruptcy of the Company, once notice of default under any Secured Debt Document has been delivered to each Secured Debt Representative pursuant to the provisions of the collateral trust agreement, the collateral trustee may (but will not be obligated to), unless it has been directed to the contrary by an Act of Required Creditors, take or refrain from taking such action with respect to any default under any Secured Debt Document as it may deem advisable and in the best interest of the holders of Secured Obligations.

Until the Discharge of Priority Lien Obligations, the holders of loans made under the Credit Agreement and other Priority Lien Obligations will have, subject to the exceptions set forth below in clauses (1) through (4) and the provisions described below under the caption “— Provisions of the Indenture Relating to Security — Relative Rights,” and subject to the rights of the holders of Permitted Prior Liens, the exclusive right to authorize and direct the collateral trustee with respect to the security documents and the Collateral including, without limitation, the exclusive right to authorize or direct the collateral trustee to enforce, collect or realize on any Collateral or exercise any other right or remedy with respect to the Collateral and neither the trustee nor the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement or the holders of other Parity Lien Obligations may authorize or direct the collateral trustee with respect to such matters. Notwithstanding the foregoing, the trustee and the holders of Notes and the creditors in respect of Indebtedness under the Hedge Agreement (together


	(1) without any condition or restriction whatsoever, at any time after the Discharge of Priority Lien Obligations;

	(2) as necessary to redeem any Collateral in a creditor’s redemption permitted by law or to deliver any notice or demand necessary to enforce (subject to the prior Discharge of Priority Lien Obligations) any right to claim, take or receive proceeds of Collateral remaining after the Discharge of Priority Lien Obligations in the event of foreclosure or other enforcement of any Permitted Prior Lien;

	(3) as necessary to perfect or establish the priority (subject to Priority Liens and other Permitted Prior Liens) of the Parity Liens upon any Collateral; or

	(4) as necessary to create, prove, preserve or protect (but not enforce) the Parity Liens upon any Collateral.

Subject to the provisions described below under the caption “— Provisions of the Indenture Relating to Security — Relative Rights,” until the Discharge of Priority Lien Obligations, none of the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement or the holders of other Parity Lien Obligations, the collateral trustee or any Parity Lien Representative will:


	(1) request judicial relief, in an insolvency or liquidation proceeding or in any other court, that would hinder, delay, limit or prohibit the lawful exercise or enforcement of any right or remedy otherwise available to the holders of any Priority Lien Obligations in respect of any Priority Liens or that would limit, invalidate, avoid or set aside any Priority Liens or subordinate any Priority Liens to the Parity Liens or grant the Parity Liens equal ranking to any Priority Liens;

	(2) oppose or otherwise contest any motion for relief from the automatic stay or from any injunction against foreclosure or enforcement of any Priority Liens made by any holder of Priority Lien Obligations or any Priority Lien Representative in any insolvency or liquidation proceedings;

	(3) oppose or otherwise contest any lawful exercise by any holder of Priority Lien Obligations or any Priority Lien Representative of the right to credit bid Priority Lien Debt at any sale in foreclosure of Priority Liens;

	(4) oppose or otherwise contest any other request for judicial relief made in any court by any holder of Priority Lien Obligations or any Priority Lien Representative relating to the lawful enforcement of any Priority Lien; or

	(5) challenge the validity, enforceability, perfection or priority of the Priority Liens.

Notwithstanding the foregoing, both before and during an insolvency or liquidation proceeding, the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the holders of other Parity Lien Obligations and the Parity Lien Representatives may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of an insolvency or liquidation proceeding against the Company or any other Pledgor in accordance with applicable law; provided that, by accepting a Note, each holder of Notes, and by entering into the Hedge Agreement, each creditor in respect of Indebtedness under the Hedge Agreement, will agree not to take any of the actions prohibited under clauses (1) through (5) of the preceding paragraph or oppose or contest any order that it has agreed not to oppose or contest under the provisions described below under the caption “— Insolvency or Liquidation Proceedings.”

Except for payments that are received by the collateral trustee, any Parity Lien Representative or any holder of Parity Lien Obligations at any time prior to the Discharge of Priority Lien Obligations and after (a) the commencement of any insolvency or liquidation proceeding in respect of the Company or any other Pledgor or (b) the collateral trustee and each Parity Lien Representative have received written notice from any Priority Lien Representative at the direction of an Act of Required Creditors stating that


	(1) no payment of money (or the equivalent of money) made by the Company or any other Pledgor to the trustee, the collateral trustee, any holder of Notes, any creditor in respect of Indebtedness under the Hedge Agreement or any holder of other Parity Lien Obligations (including, without limitation, payments and prepayments made for application to Parity Lien Obligations and all other payments and deposits made pursuant to any provision of the indenture, the Notes, the Guarantees, the Hedge Agreement or any other Parity Lien Document) will in any event be subject to the provisions of this section or otherwise affected by any of the provisions described under the caption “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens”; and

	(2) all payments permitted to be received under this section will be received by the trustee, the collateral trustee, the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the other holders of Parity Lien Obligations free from the Priority Liens and all other Liens except the Parity Liens.

Except for payments received free from the Priority Liens as provided in the preceding paragraph, subject to the provisions described below under the caption “— Provisions of the Indenture Relating to Security — Relative Rights,” all proceeds of Collateral received by the collateral trustee, any Parity Lien Representative or any holder of Parity Lien Obligations at any time prior to the Discharge of Priority Lien Obligations will be held by the collateral trustee, the applicable Parity Lien Representative or the applicable holder of Parity Lien Obligations for the account of the holders of Priority Liens and remitted to any Priority Lien Representative upon demand by such Priority Lien Representative. The Parity Liens will remain attached to and, subject to the provisions described under the caption “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens,” enforceable against all proceeds so held or remitted.

The collateral trust agreement will provide that, prior to the Discharge of Priority Lien Obligations, the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the holders of other Parity Lien Obligations, each Parity Lien Representative and the collateral trustee may not assert or enforce any right of marshalling accorded to a junior lienholder, as against the holders of any Priority Liens (in their capacity as priority lienholders). Following the Discharge of Priority Lien Obligations, the holders of Parity Lien Obligations and any Parity Lien Representative may assert their right under the Uniform Commercial Code or otherwise to any proceeds remaining following a sale or other disposition of Collateral by, or on behalf of, the holders of Priority Lien Obligations.

If in any insolvency or liquidation proceeding of the Company and prior to the Discharge of Priority Lien Obligations, the holders of any Priority Lien Obligations by an Act of Required Creditors consent to any order:


	(1) for use of cash collateral;

	(2) approving a debtor-in-possession financing secured by a Lien that is senior to or on a parity with all Priority Liens upon any property of the estate in such insolvency or liquidation proceeding;

	(3) granting any relief on account of any Priority Lien Obligations as adequate protection (or its equivalent) for the benefit of the holders of such Priority Lien Obligations in the collateral subject to Priority Liens; or


	(4) relating to a sale of assets of the Company or any other Pledgor that provides, to the extent the assets sold are to be free and clear of Liens, that all Priority Liens and Parity Liens will attach to the proceeds of the sale;

then, the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the holders of other Parity Lien Obligations, in their capacity as holders of secured claims, and each Parity Lien Representative will not oppose or otherwise contest the entry of such order, so long as none of the holders or creditors in respect of Priority Lien Obligations or any Priority Lien Representative in any respect opposes or otherwise contests any request made by the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement or the holders other Parity Lien Obligations or a Parity Lien Representative for the grant to the collateral trustee, for the benefit of the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the holders of other Parity Lien Obligations, of a junior Lien upon any property on which a Lien is (or is to be) granted under such order to secure any of the Priority Lien Obligations, co-extensive in all respects with, but subordinated (as set forth herein under the caption “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens”) to, such Lien and all Priority Liens on such property.

Notwithstanding the foregoing, both before and during an insolvency or liquidation proceeding, the holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement and the holders of other Parity Lien Obligations and the Parity Lien Representatives may take any actions and exercise any and all rights that would be available to a holder of unsecured claims, including, without limitation, the commencement of insolvency or liquidation proceedings against the Company or any other Pledgor in accordance with applicable law; provided that, by accepting a Note, each holder of Notes, and by entering into the Hedge Agreement, each creditor in respect of Indebtedness under the Hedge Agreement, will agree not to take any of the actions prohibited under clauses (1) through (5) of the second paragraph of the provisions described above under the caption “— Restrictions on Enforcement of Parity Liens” or oppose or contest any order that it has agreed not to oppose or contest under clauses (1) through (4) of the preceding paragraph.

The holders of Notes, the creditors in respect of Indebtedness under the Hedge Agreement or the holders of other Parity Lien Obligations or any Parity Lien Representative will not file or prosecute in any insolvency or liquidation proceeding any motion for adequate protection (or any comparable request for relief) based upon their interest in the Collateral under the Parity Liens, except that:


	(1) they may freely seek and obtain relief: (a) granting a junior Lien co-extensive in all respects with, but subordinated (as set forth herein under the caption “— Provisions of the Indenture Relating to Security — Ranking of Parity Liens”) to, all Liens granted in the insolvency or liquidation proceeding to, or for the benefit of, the holders of any Priority Lien Obligations; or (b) in connection with the confirmation of any plan of reorganization or similar dispositive restructuring plan; and

	(2) they may freely seek and obtain any relief upon a motion for adequate protection (or any comparable relief), without any condition or restriction whatsoever, at any time after the Discharge of Priority Lien Obligations.

The collateral trust agreement provides that if any Collateral is sold or otherwise realized upon by the collateral trustee in connection with any foreclosure, collection or other enforcement of Liens granted to the collateral trustee in the security documents, the proceeds received by the collateral trustee from such foreclosure, collection or other enforcement will be distributed by the collateral trustee in the following order of application, subject to the payment of Permitted Prior Liens to the extent required by applicable law:

First, to the payment of all amounts payable under the collateral trust agreement on account of the collateral trustee’s fees and any reasonable legal fees, costs and expenses or other liabilities of any kind

Second, to the respective Priority Lien Representatives for application to the payment of all outstanding Priority Lien Debt and any other Priority Lien Obligations that are then due and payable in such order as may be provided in the Priority Lien Documents in an amount sufficient to pay in full in cash all outstanding Priority Lien Debt and all other Priority Lien Obligations that are then due and payable (including all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Priority Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding, and including the discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Priority Lien Document) of all outstanding letters of credit constituting Priority Lien Debt);

Third, to the respective Parity Lien Representatives for application to the payment of all outstanding Parity Lien Debt and any other Parity Lien Obligations that are then due and payable and, in the case of Parity Lien Obligations arising under hedge agreements, the Hedge Outstanding Amount in such order as may be provided in the Parity Lien Documents in an amount sufficient to pay in full in cash all outstanding Parity Lien Debt and all other Parity Lien Obligations that are then due and payable and, in the case of Parity Lien Obligations arising under hedge agreements, the Hedge Outstanding Amount (including, to the extent legally permitted, all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Parity Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding, and including the discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Parity Lien Document) of all outstanding letters of credit, if any, constituting Parity Lien Debt); and

Fourth, any surplus remaining after the payment in full in cash of the amounts described in the preceding clauses will be paid to the Company or the applicable Pledgor, as the case may be, its successors or assigns, or as a court of competent jurisdiction may direct.

If any Parity Lien Representative or any holder of a Parity Lien Obligation collects or receives any proceeds of such foreclosure, collection or other enforcement that should have been applied to the payment of any Priority Lien Obligations in accordance with the paragraph above, whether after the commencement of an insolvency or liquidation proceeding or otherwise, such Parity Lien Representative or such holder of a Parity Lien Obligation, as the case may be, will forthwith deliver the same to the collateral trustee, for the account of the holders of such Priority Lien Obligations and other Obligations secured by a Permitted Prior Lien, to be applied in accordance with the provisions set forth above under this caption “— Order of Application.” Until so delivered, such proceeds will be held by that Parity Lien Representative or that holder of a Parity Lien Obligation, as the case may be, for the benefit of the holders of such Priority Lien Obligations and other Obligations secured by a Permitted Prior Lien.

This section is intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Secured Obligations, each present and future Secured Debt Representative and the collateral trustee as holder of Priority Liens and Parity Liens. The Secured Debt Representative of each future Series of Secured Debt will be required to deliver a Lien Sharing and Priority Confirmation to the collateral trustee and each other Secured Debt Representative at the time of incurrence of such Series of Secured Debt.

The collateral trust agreement provides that the collateral trustee’s Liens on the Collateral will be released:


	(1) in whole, upon (a) payment in full and discharge of all outstanding Secured Debt and all other Secured Obligations that are outstanding, due and payable at the time all of the Secured Debt is paid in full and discharged and (b) termination or expiration of all commitments to extend credit under all Secured Debt Documents and the cancellation or termination or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of Liens under the terms of the applicable Secured Debt Documents) of all outstanding letters of credit issued pursuant to any Secured Debt Documents;

	(2) as to any Collateral that is sold, transferred or otherwise disposed of by the Company or any other Pledgor to a Person that is not (either before or after such sale, transfer or disposition) the Company or a Restricted Subsidiary of the Company in a transaction or other circumstance that complies with the “Asset Sale” provisions of the indenture and is permitted by all of the other Secured Debt Documents, at the time of such sale, transfer or other disposition or to the extent of the interest sold, transferred or otherwise disposed of; provided that the collateral trustee’s Liens upon the Collateral will not be released if the sale or disposition is subject to the covenant described below under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets;”

	(3) as to a release of less than all or substantially all of the Collateral, if consent to the release of all Priority Liens on such Collateral has been given by an Act of Required Creditors; and

	(4) as to a release of all or substantially all of the Collateral, if (a) consent to the release of that Collateral has been given by the requisite percentage or number of holders of each Series of Secured Debt at the time outstanding as provided for in the applicable Secured Debt Documents, and (b) the Company has delivered an officers’ certificate to the collateral trustee certifying that all such necessary consents have been obtained.

The security documents provide that the Liens securing the Secured Debt will extend to the proceeds of any sale of Collateral. As a result, the collateral trustee’s Liens will apply to the proceeds of any such Collateral received in connection with any sale or other disposition of assets described in the preceding paragraph.

The indenture and the collateral trust agreement provide that the collateral trustee’s Liens upon the Collateral will no longer secure the Notes outstanding under the indenture or any other Obligations under the indenture, and the right of the holders of the Notes and such Obligations to the benefits and proceeds of the collateral trustee’s Liens on the Collateral will terminate and be discharged:


	(1) upon satisfaction and discharge of the indenture as set forth under the caption “— Satisfaction and Discharge;”

	(2) upon a Legal Defeasance or Covenant Defeasance of the Notes as set forth under the caption “— Legal Defeasance and Covenant Defeasance;”

	(3) upon payment in full and discharge of all Notes outstanding under the indenture and all Obligations that are outstanding, due and payable under the indenture at the time the Notes are paid in full and discharged;

	(4) in whole or in part, with the consent of the holders of the requisite percentage of Notes in accordance with the provisions described below under the caption “— Amendment, Supplement and Waiver;” or

	(5) upon release of the Liens securing the Priority Lien Debt and the Hedge Agreement; provided, however, that if, at any time following such release, any Liens upon the Collateral are


	granted to secure any Priority Lien Debt or the Hedge Agreement, then such liens shall also be granted to secure the Notes.

The collateral trust agreement provides that no amendment or supplement to the provisions of any security document will be effective without the approval of the collateral trustee acting as directed by an Act of Required Creditors, except that:


	(1) any amendment or supplement that has the effect solely of adding or maintaining Collateral, securing additional Secured Debt that was otherwise permitted by the terms of the Secured Debt Documents to be secured by the Collateral or preserving, perfecting or establishing the priority of the Liens thereon or the rights of the collateral trustee therein will become effective when executed and delivered by the Company or any other applicable Pledgor party thereto and the collateral trustee;

	(2) no amendment or supplement that reduces, impairs or adversely affects the right of any holder of Secured Obligations:


	(a) to vote its outstanding Secured Debt as to any matter described as subject to an Act of Required Creditors (or amends the provisions of this clause (2) or the definition of “Act of Required Creditors,” “Required Priority Creditors” or “Required Parity Creditors”),

	(b) to share in the order of application described above under “— Order of Application” in the proceeds of enforcement of or realization on any Collateral, or

	(c) to require that Liens securing Secured Obligations be released only as set forth in the provisions described above under the caption “— Release of Liens on Collateral,”


	will become effective without the consent of the requisite percentage or number of holders of each Series of Secured Debt so affected under the applicable Secured Debt Document; and


	(3) no amendment or supplement that imposes any obligation upon the collateral trustee or any Secured Debt Representative or adversely affects the rights of the collateral trustee or any Secured Debt Representative, respectively, in its individual capacity as such will become effective without the consent of the collateral trustee or such Secured Debt Representative, respectively.

Any amendment or supplement to the provisions of the security documents that releases Collateral will be effective only in accordance with the requirements set forth in the applicable Secured Debt Document referenced above under the caption “— Release of Liens on Collateral.” Any amendment or supplement that results in the collateral trustee’s Liens upon the Collateral no longer securing the Notes (other than a release made pursuant to the prior sentence) and the other Obligations under the indenture may only be effected in accordance with the provisions described above under the caption “— Release of Liens in Respect of Notes.”

The collateral trust agreement provides that, notwithstanding anything to the contrary under the caption “— Amendment of Security Documents,” but subject to clauses (2) and (3) above:


	(1) any mortgage or other security document that secures Parity Lien Obligations (but not Priority Lien Obligations) may be amended or supplemented with the approval of the collateral trustee acting as directed in writing by the Required Parity Creditors, unless such amendment or supplement would not be permitted under the terms of the collateral trust agreement or the other Priority Lien Documents; and

	(2) any amendment or waiver of, or any consent under, any provision of the collateral trust agreement or any other security document that secures any Priority Lien Obligations will apply automatically to any comparable provision of any comparable Parity Lien Document without the consent of or notice to any holder of Parity Lien Obligations and without any action by the Company or any other Pledgor or any holder of Notes or other Parity Lien Obligations.

In connection with any matter under the collateral trust agreement requiring a vote of holders of Secured Debt, each Series of Secured Debt will cast its votes in accordance with the Secured Debt Documents governing such Series of Secured Debt. The amount of Secured Debt to be voted by a Series of Secured Debt will equal (1) the aggregate principal amount of Secured Debt held by such Series of Secured Debt (including outstanding letters of credit whether or not then available or drawn), plus (2) other than in connection with an exercise of remedies, the aggregate unfunded commitments to extend credit which, when funded, would constitute Indebtedness of such Series of Secured Debt plus (3) in the case of Parity Lien Obligations arising under hedge agreements, the Hedge Outstanding Amount. Following and in accordance with the outcome of the applicable vote under its Secured Debt Documents, the Secured Debt Representative of each Series of Secured Debt will vote the total amount of Secured Debt under that Series as a block in respect of any vote under the collateral trust agreement.


	(1) anything to the contrary contained in the security documents;

	(2) the time of incurrence of any Series of Parity Lien Debt;

	(3) the order or method of attachment or perfection of any Liens securing any Series of Parity Lien Debt;

	(4) the time or order of filing or recording of financing statements, mortgages or other documents filed or recorded to perfect any Lien upon any Collateral;

	(5) the time of taking possession or control over any Collateral;

	(6) that any Parity Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

	(7) the rules for determining priority under any law governing relative priorities of Liens:


	(a) all Parity Liens granted at any time by the Company or any other Pledgor will secure, equally and ratably, all present and future Parity Lien Obligations; and

	(b) all proceeds of all Parity Liens granted at any time by the Company or any other Pledgor will be allocated and distributed equally and ratably on account of the Parity Lien Debt and other Parity Lien Obligations.

This section is intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Parity Lien Obligations, each present and future Parity Lien Representative and the collateral trustee as holder of Parity Liens. The Parity Lien Representative of each future Series of Parity Lien Debt will be required to deliver a Lien Sharing and Priority Confirmation to the collateral trustee and the trustee at the time of incurrence of such Series of Parity Lien Debt.


	(1) anything to the contrary contained in the security documents;

	(2) the time of incurrence of any Series of Secured Debt;

	(3) the order or method of attachment or perfection of any Liens securing any Series of Secured Debt;


	(4) the time or order of filing or recording of financing statements, mortgages or other documents filed or recorded to perfect any Lien upon any Collateral;

	(5) the time of taking possession or control over any Collateral;

	(6) that any Priority Lien may not have been perfected or may be or have become subordinated, by equitable subordination or otherwise, to any other Lien; or

	(7) the rules for determining priority under any law governing relative priorities of Liens,

all Parity Liens at any time granted by the Company or any other Pledgor will be subject and subordinate to all Priority Liens securing Priority Lien Obligations up to the Priority Lien Cap.

The provisions under the caption “— Ranking of Parity Liens” are intended for the benefit of, and will be enforceable as a third party beneficiary by, each present and future holder of Priority Lien Obligations, each present and future Priority Lien Representative and the collateral trustee as holder of the Priority Liens. No other Person will be entitled to rely on, have the benefit of or enforce those provisions. The Parity Lien Representative of each future Series of Parity Lien Debt will be required to deliver a Lien Sharing and Priority Confirmation to the collateral trustee and each Priority Lien Representative at the time of incurrence of such Series of Parity Lien Debt.

In addition, the provisions under the caption “— Ranking of Parity Liens” are intended solely to set forth the relative ranking, as Liens, of the Liens securing Parity Lien Debt as against the Priority Liens. Neither the Notes, the creditors in respect of Indebtedness under the Hedge Agreement nor any holder of other Parity Lien Obligations nor the exercise or enforcement of any right or remedy for the payment or collection thereof are intended to be, or will ever be by reason of the foregoing provision, in any respect subordinated, deferred, postponed, restricted or prejudiced.


	(1) impairs, as between the Company and the holders of the Notes, the obligation of the Company to pay principal of, premium and interest and Special Interest, if any, on the Notes in accordance with their terms or any other obligation of the Company or any other Pledgor;

	(2) affects the relative rights of holders of Notes as against any other creditors of the Company or any other Pledgor (other than holders of Priority Liens, Permitted Prior Liens or other Parity Liens);

	(3) restricts the right of any holder of Notes to sue for payments that are then due and owing (but not enforce any judgment in respect thereof against any Collateral to the extent specifically prohibited by the provisions described above under the captions “— Collateral Trust Agreement — Restrictions on Enforcement of Parity Liens” or “— Collateral Trust Agreement — Insolvency or Liquidation Proceedings”);

	(4) restricts or prevents any holder of Notes, any creditor in respect of Indebtedness under the Hedge Agreement or any holder of other Parity Lien Obligations, the collateral trustee or any Parity Lien Representative from exercising any of its rights or remedies upon a Default or Event of Default not specifically restricted or prohibited by (a) “— Collateral Trust Agreement — Restrictions on Enforcement of Parity Liens” or (b) “— Collateral Trust Agreement — Insolvency or Liquidation Proceedings”; or

	(5) restricts or prevents any holder of Notes, any creditor in respect of Indebtedness under the Hedge Agreement or any holder of other Parity Lien Obligations, the collateral trustee or any Parity Lien Representative from taking any lawful action in an insolvency or liquidation proceeding not specifically restricted or prohibited by (a) “— Collateral Trust Agreement — Restrictions on Enforcement of Parity Liens” or (b) “— Collateral Trust Agreement — Insolvency or Liquidation Proceedings.”

The indenture provides that the Company will comply with the provisions of TIA Section 314.

To the extent applicable, the Company will cause TIA Section 313(b), relating to reports, and TIA Section 314(d), relating to the release of property or securities subject to the Lien of the security documents, to be complied with. Any certificate or opinion required by TIA Section 314(d) may be made by an officer of the Company except in cases where TIA Section 314(d) requires that such certificate or opinion be made by an independent Person, which Person will be an independent engineer, appraiser or other expert selected by or reasonably satisfactory to the trustee. Notwithstanding anything to the contrary in this paragraph, the Company will not be required to comply with all or any portion of TIA Section 314(d) if it determines, in good faith based on advice of counsel, that under the terms of TIA Section 314(d) and/or any interpretation or guidance as to the meaning thereof of the SEC and its staff, including “no action” letters or exemptive orders, all or any portion of TIA Section 314(d) is inapplicable to one or a series of released Collateral.

The indenture and the security documents provide that the Company and each of the other Pledgors will do or cause to be done all acts and things that may be required, or that the collateral trustee from time to time may reasonably request, to assure and confirm that the collateral trustee holds, for the benefit of the holders of Secured Obligations, duly created and enforceable and perfected Liens upon the Collateral (including any property or assets that are acquired or otherwise become Collateral after the Notes are issued), in each case, as contemplated by, and with the Lien priority required under, the Secured Debt Documents.

The indenture and the security documents also provide that if the Company or any of the Pledgors (other than the Parent) acquires any material proved producing Hydrocarbon Properties or develops any Hydrocarbon Properties that are producing in commercial quantities, then the Company or such Pledgor will, not less than semi-annually, take all such actions and execute all documents that the collateral trustee may reasonably request to create in favor of the collateral trustee, for the benefit of the holders of the Secured Obligations, valid and perfected security interests in such Hydrocarbon Properties.

Upon the reasonable request of the collateral trustee or any Secured Debt Representative at any time and from time to time, the Company and each of the other Pledgors will promptly execute, acknowledge and deliver such security documents, instruments, certificates, notices and other documents, and take such other actions as shall be reasonably required, or that the collateral trustee may reasonably request, to create, perfect, protect, assure or enforce the Liens and benefits intended to be conferred, in each case as contemplated by the Secured Debt Documents for the benefit of the holders of Secured Obligations.


	(1) keep their properties adequately insured at all times by financially sound and reputable insurers;

	(2) maintain such other insurance, to such extent and against such risks (and with such deductibles, retentions and exclusions), including fire and other risks insured against by extended coverage and coverage for acts of terrorism, as is customary with companies in the same or similar businesses operating in the same or similar locations, including public liability insurance against claims for personal injury or death or property damage occurring upon, in, about or in connection with the use of any properties owned, occupied or controlled by them;

	(3) maintain such other insurance as may be required by law; and

	(4) maintain such other insurance as may be required by the security documents.

Upon the request of the collateral trustee, the Company and the other Pledgors will furnish to the collateral trustee full information as to their property and liability insurance carriers. Holders of Secured

At any time prior to July 15, 2007, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of Notes (including any Additional Notes) issued under the indenture at a redemption price of 108.750% of the principal amount, plus accrued and unpaid interest and Special Interest, if any, to the redemption date, with the net cash proceeds of one or more Equity Offerings or a contribution to the Company’s common equity capital made with the net cash proceeds of a concurrent offering of common stock of the Company’s direct parent; provided that:


	(1) at least 65% of the aggregate principal amount of Notes (including any Additional Notes) issued under the indenture (excluding Notes held by the Company and its Subsidiaries) remains outstanding immediately after the occurrence of such redemption; and

	(2) the redemption occurs within 60 days of the date of the closing of such Equity Offering or such contribution to the Company’s common equity capital, as applicable.

At any time prior to July 15, 2008, the Company may also redeem all or a part of the Notes, upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder’s registered address, at a redemption price equal to 100% of the principal amount of Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest and Special Interest, if any, to the date of redemption, subject to the rights of holders of Notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding two paragraphs, the Notes will not be redeemable at the Company’s option prior to July 15, 2008.

On or after July 15, 2008, the Company may redeem all or a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and Special Interest, if any, on the Notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on July 15 of the years indicated below, subject to the rights of holders of Notes on the relevant record date to receive interest on the relevant interest payment date:

Unless the Company defaults in the payment of the redemption price, interest will cease to accrue on the Notes or portions thereof called for redemption on the applicable redemption date.

The Company is not required to make mandatory redemption or sinking fund payments with respect to the Notes.

If a Change of Control occurs, each holder of Notes will have the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple of $1,000) of that holder’s Notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control

Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest and Special Interest, if any, on the Notes repurchased to the date of purchase, subject to the rights of holders of Notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, the Company will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.


	(1) accept for payment all Notes or portions of Notes properly tendered pursuant to the Change of Control Offer;

	(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes properly tendered; and

	(3) deliver or cause to be delivered to the trustee the Notes properly accepted together with an officers’ certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

The paying agent will promptly mail to each holder of Notes properly tendered the Change of Control Payment for such Notes, and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the Notes to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all Notes properly tendered and not withdrawn under the Change of Control Offer, or (2) notice of redemption has been given pursuant to the indenture as described above under the caption “— Optional Redemption,” unless and until there is a default in payment of the applicable redemption price.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of Notes to require the Company to repurchase its Notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:


	(1) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the Fair Market Value of the assets or Equity Interests issued or sold or otherwise disposed of; and

	(2) at least 75% of the consideration received in the Asset Sale by the Company or such Restricted Subsidiary is in the form of cash. For purposes of this provision, each of the following will be deemed to be cash:


	(a) any liabilities, as shown on the Company’s most recent consolidated balance sheet, of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the Notes or any Note Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability;

	(b) any securities, Notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are, within 90 days by the Company or such Restricted Subsidiary, converted by the Company or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion; and

	(c) any stock or assets of the kind referred to in clauses (2) or (4) of the next paragraph of this covenant.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale, other than a Sale of Collateral, the Company (or the applicable Restricted Subsidiary, as the case may be) may apply such Net Proceeds at its option:


	(1) to repay Priority Lien Debt and, if such Priority Lien Debt is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto;

	(2) to acquire all or substantially all of the assets of, or any Capital Stock of, another Oil and Gas Business, if, after giving effect to any such acquisition of Capital Stock, the Oil and Gas Business is or becomes a Restricted Subsidiary of the Company;

	(3) to make a capital expenditure; or

	(4) to acquire other assets that are not classified as current assets under GAAP and that are used or useful in an Oil and Gas Business.

Within 360 days after the receipt of any Net Proceeds from an Asset Sale that constitutes a Sale of Collateral or from a Casualty Event, the Company (or the Restricted Subsidiary that owned those assets, as the case may be) may apply those Net Proceeds to purchase other long-term assets that would constitute Collateral or to repay Priority Lien Debt and, if such Priority Lien Debt is revolving credit Indebtedness, to correspondingly reduce commitments with respect thereto.

Any Net Proceeds from Asset Sales or Casualty Events that are not applied or invested as provided in the second or third paragraph of this covenant will constitute “Excess Proceeds.” If following such application or investment, the percentage of the Company’s expected production volumes hedged exceeds a range to be agreed between the Hedge Counterparty and the Company at the time each hedge transaction is consummated, then the Company shall terminate that portion of the hedges necessary in order to have the volumes hedged be within such range, and shall apply Excess Proceeds to effect such termination. When the aggregate amount of Excess Proceeds not so applied exceeds $15.0 million, within ten days thereof, the Company will make an Asset Sale Offer to all holders of Notes and all holders of other Parity Lien Debt containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets to purchase the maximum principal amount of

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of Notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such compliance.

The agreements governing the Company’s other Indebtedness contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the Notes. The exercise by the holders of Notes of their right to require the Company to repurchase the Notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on the Company. In the event a Change of Control or Asset Sale occurs at a time when the Company is prohibited from purchasing Notes, the Company could seek the consent of its senior lenders to the purchase of Notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain a consent or repay those borrowings, the Company will remain prohibited from purchasing Notes. In that case, the Company’s failure to purchase tendered Notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, the Company’s ability to pay cash to the holders of Notes upon a repurchase may be limited by the Company’s then existing financial resources. See “Risk Factors — We may not be able to repurchase the Notes upon a change of control.”

If less than all of the Notes are to be redeemed at any time, the trustee will select Notes for redemption on a pro rata basis unless otherwise required by law or applicable stock exchange requirements.

No Notes of $1,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of Notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of that Note that is to be redeemed. A new Note in principal amount equal to the unredeemed portion of the original Note will be issued in the name of the holder of Notes upon cancellation of the original Note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on Notes or portions of Notes called for redemption.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:


	(1) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company and other than dividends or distributions payable to the Company or a Restricted Subsidiary of the Company);

	(2) purchase, redeem or otherwise acquire or retire for value any Equity Interests of the Company or any direct or indirect parent of the Company;

	(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness of the Company or any Guarantor that is contractually subordinated to the Notes or to any Note Guarantee (excluding any intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries), except a payment of interest or principal at the Stated Maturity thereof; or

	(4) make any Restricted Investment

(all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),


	(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

	(2) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and

	(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries since the date of the indenture (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (7) and (9) of the next succeeding paragraph), is less than the sum, without duplication, of:


	(a) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing after the date of the indenture to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus

	(b) 100% of the aggregate net proceeds received by the Company since the date of the indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Company); plus

	(c) to the extent that any Restricted Investment that was made after the date of the indenture is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash


	return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment; plus

	(d) to the extent that any Unrestricted Subsidiary of the Company designated as such after the date of the indenture is redesignated as a Restricted Subsidiary after the date of the indenture, the lesser of (i) the Fair Market Value of the Company’s Investment in such Subsidiary as of the date of such redesignation and (ii) such Fair Market Value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary after the date of the indenture; plus

	(e) 100% of any dividends received by the Company or a Restricted Subsidiary of the Company after the date of the indenture from an Unrestricted Subsidiary of the Company, to the extent that such dividends were not otherwise included in the Consolidated Net Income of the Company for such period.


	(1) the payment of any dividend or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend or redemption payment would have complied with the provisions of the indenture;

	(2) the making of any Restricted Payment in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock) or from the substantially concurrent contribution of common equity capital to the Company; provided that the amount of any such net cash proceeds that are utilized for any such Restricted Payment will be excluded from clause (3)(b) of the preceding paragraph;

	(3) the repurchase, redemption, defeasance or other acquisition or retirement for value of the Company’s 9 7/8% Senior Subordinated Notes due 2007 with the net proceeds of this offer of the Notes and Indebtedness under the Credit Facilities;

	(4) the repurchase, redemption, defeasance or other acquisition or retirement for value of any Indebtedness of the Company or any Guarantor that is contractually subordinated to the Notes or to any Note Guarantee (in addition to that referred to in clause (3) above) with the net cash proceeds from a substantially concurrent incurrence of Permitted Refinancing Indebtedness;

	(5) so long as no Default has occurred and is continuing or would be caused thereby, the payment of any dividend (or, in the case of any partnership or limited liability company, any similar distribution) by a Restricted Subsidiary of the Company to the holders of its Equity Interests on a pro rata basis;

	(6) so long as no Default has occurred and is continuing or would be caused thereby, the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any current or former officer, director or employee of the Company or any of its Restricted Subsidiaries pursuant to any equity subscription agreement, stock option agreement, shareholders’ agreement or similar agreement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $2.0 million in any twelve-month period;

	(7) so long as no Default has occurred and is continuing or would be caused thereby, the repurchase of Equity Interests deemed to occur upon the exercise of stock options to the extent such Equity Interests represent a portion of the exercise price of those stock options;

	(8) so long as no Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of the Company or any Restricted Subsidiary of the Company issued on or after


	the date of the indenture in accordance with the Fixed Charge Coverage Ratio test described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;”

	(9) Permitted Payments to Parent; and

	(10) so long as no Default has occurred and is continuing or would be caused thereby, other Restricted Payments in an aggregate amount not to exceed $15.0 million since the date of the indenture.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors of the Company whose resolution with respect thereto will be delivered to the trustee. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the Fair Market Value exceeds $25.0 million.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), and the Company will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Company may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Guarantors may incur Indebtedness (including Acquired Debt) or issue preferred stock, if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred stock is issued, as the case may be, would have been at least 2.5 to 1, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):


	(1) the incurrence by the Company and any Guarantor of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of the Company and its Restricted Subsidiaries thereunder) not to exceed:


	(a) prior to July 7, 2008, the greater of (i) $170.0 million less the aggregate amount of all Net Proceeds of Asset Sales applied by the Company or any of its Restricted Subsidiaries since the date of the indenture to repay any term Indebtedness under a Credit Facility or to repay any revolving credit Indebtedness under a Credit Facility and effect a corresponding commitment reduction thereunder pursuant to the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales” less any amount that is released by the Hedge Counterparty under the Hedge Letter of Credit and (ii) 30% of ACNTA as of the date of such incurrence; and

	(b) on or after July 7, 2008, the greater of (i) $130.0 million less the aggregate amount of all Net Proceeds of Asset Sales applied by the Company or any of its Restricted Subsidiaries since the date of the indenture to repay any term Indebtedness under a Credit Facility or to repay any revolving credit Indebtedness under a Credit Facility and effect a corresponding commitment reduction thereunder pursuant to the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales” less any amount that is released by the


	Hedge Counterparty under the Hedge Letter of Credit and (ii) 30% of ACNTA as of the date of such incurrence less $40.0 million; provided that such amounts in the foregoing clauses (i) and (ii) of this paragraph shall be reduced by an additional $10.0 million on each of the fifth, sixth and seventh anniversaries of the date of the indenture;


	(2) the incurrence by the Company and any Guarantor of Indebtedness under the Hedge Agreement;

	(3) the incurrence by the Company and its Restricted Subsidiaries of the Existing Indebtedness;

	(4) the incurrence by the Company and the Guarantors of Indebtedness represented by the Notes and the related Note Guarantees to be issued on the date of the indenture and the exchange notes and the related Note Guarantees to be issued pursuant to the registration rights agreement;

	(5) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge any Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (3), (4), (5) or (14) of this paragraph;

	(6) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:


	(a) if the Company or any Guarantor is the obligor on such Indebtedness and the payee is not the Company or a Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the Notes, in the case of the Company, or the Note Guarantee, in the case of a Guarantor; and

	(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary of the Company, will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);


	(7) the issuance by any of the Company’s Restricted Subsidiaries to the Company or to any of its Restricted Subsidiaries of shares of preferred stock; provided, however, that:


	(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than the Company or a Restricted Subsidiary of the Company; and

	(b) any sale or other transfer of any such preferred stock to a Person that is not either the Company or a Restricted Subsidiary of the Company, will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);


	(8) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business (other than pursuant to the Hedge Agreement);

	(9) the guarantee by the Company or any of the Guarantors of Indebtedness of the Company or a Restricted Subsidiary of the Company that was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated to or pari passu with the Notes, then the Guarantee shall be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;

	(10) in-kind obligations relating to net oil and natural gas balancing positions arising in the ordinary course of business;


	(11) any obligation arising from agreements of the Company or a Restricted Subsidiary of the Company providing for indemnification, guarantee, adjustment of purchase price, holdback, contingency payment obligations based on the performance of the acquired or disposed asset or similar obligations, in each case, incurred or assumed in connection with the acquisition or disposition of any business, asset or Capital Stock of a Restricted Subsidiary of the Company;

	(12) the incurrence by the Company or any of the Guarantors of Indebtedness in respect of workers’ compensation claims, self-insurance obligations, bankers’ acceptances, performance and surety bonds in the ordinary course of business;

	(13) the incurrence by the Company or any of the Guarantors of Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument inadvertently drawn against insufficient funds, so long as such Indebtedness is covered within five business days; and

	(14) the incurrence by the Company or any of the Guarantors of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (14), not to exceed $25.0 million.

The Company will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of the Company or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the Notes and the applicable Note Guarantee on substantially identical terms; provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of the Company solely by virtue of being unsecured or by virtue of being secured on a first or junior Lien basis.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (14) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify such item of Indebtedness on the date of its incurrence, or later reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant. Indebtedness under Credit Facilities outstanding on the date on which Notes are first issued and authenticated under the indenture will initially be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of preferred stock as Indebtedness due to a change in accounting principles, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount of any such accrual, accretion or payment is included in Fixed Charges of the Company as accrued. The amount of any premium payable on Indebtedness upon the prepayment, redemption or other retirement for value of such Indebtedness shall be disregarded in determining the amount of such Indebtedness. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values.


	(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

	(2) the principal amount of the Indebtedness, in the case of any other Indebtedness; and


	(3) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:


	(a) the Fair Market Value of such assets at the date of determination; and

	(b) the amount of the Indebtedness of the other Person.

The Company will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness, Attributable Debt or trade payables upon any of their property or assets, now owned or hereafter acquired, unless all payments due under the indenture and the Notes are secured on an equal and ratable basis with the obligations so secured until such time as such obligations are no longer secured by a Lien.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:


	(1) pay dividends or make any other distributions on its Capital Stock to the Company or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any indebtedness owed to the Company or any of its Restricted Subsidiaries;

	(2) make loans or advances to the Company or any of its Restricted Subsidiaries; or

	(3) sell, lease or transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:


	(1) agreements governing Existing Indebtedness, the Credit Facilities and the Hedging Agreement as in effect on the date of the indenture and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements; provided that the amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

	(2) the indenture, the Notes and the Note Guarantees;

	(3) applicable law, rule, regulation or order;

	(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired; provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

	(5) customary non-assignment provisions in contracts and licenses entered into in the ordinary course of business;

	(6) purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;


	(7) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending the sale or other disposition;

	(8) Permitted Refinancing Indebtedness; provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

	(9) Liens permitted to be incurred under the provisions of the covenant described above under the caption “— Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

	(10) provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements entered into with the approval of the Company’s Board of Directors, which limitation is applicable only to the assets that are the subject of such agreements;

	(11) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

	(12) restrictions on cash or other deposits by parties under agreements entered into in the ordinary course of the Oil and Gas Business of the types described in the definition of Permitted Investments; and

	(13) customary restrictions on the disposition or distribution of assets or property in agreements entered into the ordinary course of business of the Oil and Gas Business of the types described in the definition of Permitted Investments.

The Company will not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the surviving Person); or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:


	(1) either: (a) the Company is the surviving Person; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, conveyance or other disposition has been made is either (i) a corporation organized or existing under the laws of the United States, any state of the United States or the District of Columbia, or (ii) a partnership or limited liability company organized or existing under the laws of the United States, any state thereof or the District of Columbia that has at least one Restricted Subsidiary that is a corporation organized or existing under the laws of the United States, any state thereof or the District of Columbia, which corporation becomes a co-issuer of the Notes pursuant to a supplemental indenture duly and validly executed by the trustee;

	(2) the Person formed by or surviving any such consolidation or merger (if other than the Company) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of the Company under the Notes, the indenture and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee;

	(3) immediately after such transaction, no Default or Event of Default exists;

	(4) the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, conveyance or other disposition has been made would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and


	(5) the trustee shall have received an opinion of counsel satisfactory to the trustee stating that the Parity Lien granted under the security documents on the Collateral to secure the Notes shall be an enforceable and perfected second-priority Lien after giving effect to such consolidation, merger, sale, assignment, transfer, conveyance or other disposition.

In addition, the Company will not, directly or indirectly, lease all or substantially all of the properties and assets of it and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to any other Person.


	(1) a merger of the Company with an Affiliate solely for the purpose of reincorporating the Company in another jurisdiction; or

	(2) any consolidation or merger, or any sale, assignment, transfer, conveyance, lease or other disposition of assets between or among the Company and its Restricted Subsidiaries.

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Company (each, an “Affiliate Transaction”), unless:


	(1) the Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

	(2) the Company delivers to the trustee:


	(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $5.0 million, a resolution of the Board of Directors of the Company set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors, if any, of the Company; and

	(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $15.0 million, an opinion as to the fairness to the Company or such Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:


	(1) any employment agreement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business and payments pursuant thereto;

	(2) transactions between or among the Company and/or its Restricted Subsidiaries;

	(3) transactions with a Person (other than an Unrestricted Subsidiary of the Company) that is an Affiliate of the Company solely because the Company owns, directly or through a Restricted Subsidiary, an Equity Interest in, or controls, such Person;

	(4) payment of reasonable directors’ fees to Persons who are not otherwise Affiliates of the Company;

	(5) any issuance of Equity Interests (other than Disqualified Stock) of the Company to Affiliates of the Company;


	(6) Restricted Payments or Permitted Investments that do not violate the provisions of the indenture described above under the caption “— Restricted Payments;”

	(7) payment of fees not in excess of $1.0 million per annum pursuant to the Management Agreement as in effect on the date of the indenture, including any amendment or replacement agreement that is no more disadvantageous to the holders of the Notes in any material respect than the original Management Agreement; provided that the amount of the fee shall not exceed $1.0 million per annum at any time;

	(8) payment of fees not in excess of $1.4 million, payable to Carlyle/ Riverstone Global Energy and Power Fund II, L.P., or one or more of its Affiliates, upon the consummation of the Merger;

	(9) payment of fees not in excess of $5.9 million, payable to TPG Partners II L.P., upon the consummation of the Merger, pursuant to the Transaction Advisory Agreement as in effect on the date of the indenture;

	(10) loans or advances to employees in the ordinary course of business not to exceed $1.0 million in the aggregate at any one time outstanding; and

	(11) Permitted Parent Payments.

The Company will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than Oil and Gas Businesses, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

If the Company or any of its Restricted Subsidiaries acquires or creates another Domestic Subsidiary after the date of the indenture, which Domestic Subsidiary guarantees any Priority Lien Debt, then that newly acquired or created Domestic Subsidiary will become a Guarantor and execute a supplemental indenture and deliver an opinion of counsel satisfactory to the trustee within ten business days of the date on which it was acquired or created; provided that any Domestic Subsidiary that constitutes an Immaterial Subsidiary need not become a Guarantor until such time as it ceases to be an Immaterial Subsidiary.

The Board of Directors of the Company may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary designated as Unrestricted will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption “— Restricted Payments” or under one or more clauses of the definition of Permitted Investments, as determined by the Company. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors of the Company may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if that redesignation would not cause a Default.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “— Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted

Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company will be in default of such covenant. The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Company; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any holder of Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the Notes unless such consideration is offered to be paid and is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

The Company will not, and will not permit any of the Guarantors to, terminate the Hedge Agreement or the obligations thereunder during the term of the Notes other than in connection with a partial termination in connection with an Asset Sale or Casualty Event. See “— Repurchase at the Option of Holders — Asset Sales.”


	(1) the Notes have an Investment Grade Rating; and

	(2) no Default or Event of Default shall have occurred and be continuing,

then, beginning on that day and subject to the provisions of the following paragraph, the covenants specifically listed under the following captions in this offering circular will be suspended:


	(1) “— Repurchase at the Option of Holders — Asset Sales;”

	(2) “— Restricted Payments;”

	(3) “— Incurrence of Indebtedness and Issuance of Preferred Stock;”

	(4) “— Dividend and Other Payment Restrictions Affecting Subsidiaries;”

	(5) “— Transactions with Affiliates;” and

	(6) clause (4) under “— Merger, Consolidation or Sale of Assets.”

Notwithstanding the foregoing, if the rating assigned by either such rating agency should subsequently decline to below the Investment Grade Rating, the foregoing covenants will be reinstituted as of and from the date of such rating decline. Calculations under the reinstated “Restricted Payments” covenant will be made as if the “Restricted Payments” covenant had been in effect since the date of the indenture except that no default will be deemed to have occurred solely by reason of a Restricted Payment made while that covenant was suspended. There can be no assurance that the Notes will ever achieve an investment grade rating or that any such rating will be maintained.

Whether or not required by the rules and regulations of the SEC, so long as any Notes are outstanding, the Company will furnish to the holders of Notes or cause the trustee to furnish to the holders of Notes, within the time periods specified in the SEC’s rules and regulations:


	(1) all quarterly and annual reports that would be required to be filed with the SEC on Forms 10-Q and 10-K if the Company were required to file such reports; and

	(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

All such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports. Each annual report on Form 10-K will include a report on the Company’s consolidated financial statements by the Company’s certified independent accountants. In addition, the Company will file a copy of each of the reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the rules and regulations applicable to such reports (unless the SEC will not accept such a filing) and will post the reports on its website within those time periods.

If, at any time, the Company is no longer subject to the periodic reporting requirements of the Exchange Act for any reason, the Company will nevertheless continue filing the reports specified in the preceding paragraphs of this covenant with the SEC within the time periods specified above unless the SEC will not accept such a filing. The Company will not take any action for the purpose of causing the SEC not to accept any such filings. If, notwithstanding the foregoing, the SEC will not accept the Company’s filings for any reason, the Company will post the reports referred to in the preceding paragraphs on its website within the time periods that would apply if the Company were required to file those reports with the SEC.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

In addition, the Company and the Guarantors agree that, for so long as any Notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of Notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.


	(1) default for 30 days in the payment when due of interest on, or Special Interest, if any, with respect to, the Notes;

	(2) default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the Notes;

	(3) failure by the Company or any of its Restricted Subsidiaries to comply with the provisions described under the captions “— Repurchase at the Option of Holders — Change of Control,” “— Repurchase at the Option of Holders — Asset Sales,” “— Certain Covenants — Restricted Payments,” “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” or “— Certain Covenants — Merger, Consolidation or Sale of Assets;”


	(4) failure by the Company or any of its Restricted Subsidiaries for 60 days after notice to the Company by the trustee or the holders of at least 25% in aggregate principal amount of the Notes then outstanding voting as a single class to comply with any of the other agreements in the indenture or the security documents;

	(5) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), including, without limitation, the Hedge Agreement, whether such Indebtedness or Guarantee now exists, or is created after the date of the indenture, if that default:


	(a) is caused by a failure to pay principal of, or interest or premium, if any, on, such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a “Payment Default”); or

	(b) results in the acceleration of such Indebtedness prior to its express maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $10.0 million or more;


	(6) failure by the Company or any of its Restricted Subsidiaries to pay final judgments entered by a court or courts of competent jurisdiction aggregating in excess of $10.0 million, which judgments are not paid, discharged or stayed for a period of 60 days;

	(7) the occurrence of any of the following:


	(a) except as permitted by the indenture, any security document ceases for any reason to be fully enforceable; provided, that it will not be an Event of Default under this clause (7)(a) if the sole result of the failure of one or more security documents to be fully enforceable is that any Parity Lien purported to be granted under such security documents on Collateral, individually or in the aggregate, having a Fair Market Value of not more than $10.0 million ceases to be an enforceable and perfected third-priority Lien, subject only to Permitted Prior Liens;

	(b) any Parity Lien purported to be granted under any security document on Collateral, individually or in the aggregate, having a Fair Market Value in excess of $10.0 million ceases to be an enforceable and perfected second-priority Lien, subject only to Permitted Prior Liens; or

	(c) the Company or any other Pledgor, or any Person acting on behalf of any of them, denies or disaffirms, in writing, any obligation of the Company or any other Pledgor set forth in or arising under any security document;


	(8) except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee; and

	(9) certain events of bankruptcy or insolvency described in the indenture with respect to the Company or any of its Restricted Subsidiaries that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Company, any Restricted Subsidiary of the Company that is a Significant Subsidiary or any group of Restricted Subsidiaries of the Company that, taken together, would constitute a Significant Subsidiary, all Outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then Outstanding Notes may declare all the Notes to be due and payable immediately.

Subject to certain limitations, holders of a majority in aggregate principal amount of the then Outstanding Notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the Notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium or Special Interest, if any.

Subject to the provisions of the indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of Notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest or Special Interest, if any, when due, no holder of a Note may pursue any remedy with respect to the indenture or the Notes unless:


	(1) such holder has previously given the trustee notice that an Event of Default is continuing;

	(2) holders of at least 25% in aggregate principal amount of the then Outstanding Notes have requested the trustee to pursue the remedy;

	(3) such holders have offered the trustee reasonable security or indemnity against any loss, liability or expense;

	(4) the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

	(5) holders of a majority in aggregate principal amount of the then Outstanding Notes have not given the trustee a direction inconsistent with such request within such 60-day period.

The holders of a majority in aggregate principal amount of the then Outstanding Notes by notice to the trustee may, on behalf of the holders of all of the Notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest or premium or Special Interest, if any, on, or the principal of, the Notes.

The Company is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default.

No director, officer, employee, incorporator or stockholder of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or the Guarantors under the Notes, the indenture, the Note Guarantees, the Note Documents or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. The waiver may not be effective to waive liabilities under the federal securities laws.

The Company may at any time, at the option of its Board of Directors evidenced by a resolution set forth in an officers’ certificate, elect to have all of its obligations discharged with respect to the Outstanding Notes and all obligations of the Guarantors discharged with respect to their Note Guarantees (“Legal Defeasance”) except for:


	(1) the rights of holders of Outstanding Notes to receive payments in respect of the principal of, or interest or premium and Special Interest, if any, on, such Notes when such payments are due from the trust referred to below;


	(2) the Company’s obligations with respect to the Notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

	(3) the rights, powers, trusts, duties and immunities of the trustee, and the Company’s and the Guarantors’ obligations in connection therewith; and

	(4) the Legal Defeasance and Covenant Defeasance provisions of the indenture.

In addition, the Company may, at its option and at any time, elect to have the obligations of the Company and the Guarantors released with respect to certain covenants (including its obligation to make Change of Control Offers and Asset Sale Offers) that are described in the indenture (“Covenant Defeasance”) and all obligations of the Guarantors with respect to their Note Guarantees discharged, and thereafter any omission to comply with those covenants or Notes Guarantees will not constitute a Default or Event of Default with respect to the Notes. In the event Covenant Defeasance occurs, certain events (not including, with respect to the Company, non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “Events of Default and Remedies” will no longer constitute an Event of Default with respect to the Notes.


	(1) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the Notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium and Special Interest, if any, on, the outstanding Notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Company must specify whether the Notes are being defeased to such stated date for payment or to a particular redemption date;

	(2) in the case of Legal Defeasance, the Company must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

	(3) in the case of Covenant Defeasance, the Company must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

	(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which the Company or any Guarantor is a party or by which the Company or any Guarantor is bound;

	(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

	(6) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the holders of Notes over the other creditors


	of the Company with the intent of defeating, hindering, delaying or defrauding any creditors of the Company or others; and

	(7) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

The Collateral will be released from the Lien securing the Notes, as provided under the caption “— Collateral Trust Agreement — Release of Liens in Respect of Notes,” upon a Legal Defeasance or Covenant Defeasance in accordance with the provisions described above.

Except as provided in the next three succeeding paragraphs, the indenture or the Notes or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes), and any existing Default or Event of Default or compliance with any provision of the indenture or the Notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding Notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes).

Without the consent of each holder of Notes affected, an amendment, supplement or waiver may not (with respect to any Notes held by a non-consenting holder):


	(1) reduce the principal amount of Notes whose holders must consent to an amendment, supplement or waiver;

	(2) reduce the principal of or change the fixed maturity of any Note or alter the provisions with respect to the redemption of the Notes (other than provisions relating to the covenants described above under the caption “— Repurchase at the Option of Holders”);

	(3) reduce the rate of or change the time for payment of interest, including default interest, on any Note;

	(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, or Special Interest, if any, on, the Notes (except a rescission of acceleration of the Notes by the holders of at least a majority in aggregate principal amount of the then outstanding Notes and a waiver of the payment default that resulted from such acceleration);

	(5) make any Note payable in money other than that stated in the Notes;

	(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of Notes to receive payments of principal of, or interest or premium or Special Interest, if any, on, the Notes;

	(7) waive a redemption payment with respect to any Note (other than a payment required by one of the covenants described above under the caption “— Repurchase at the Option of Holders”);

	(8) release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture;

	(9) release all or substantially all of the Collateral from the Liens created by the security documents except as specifically provided for in the applicable indenture and the security documents; or

	(10) make any change in the preceding amendment and waiver provisions.

In addition, any amendment to, or waiver of, the provisions of the indenture or any security document that has the effect of releasing any portion of the Collateral from the Liens securing the Notes will require the consent of the holders of at least 66 2/3% in aggregate principal amount of the Notes then outstanding.

Notwithstanding the preceding, without the consent of any holder of Notes, the Company, the Guarantors and the trustee may amend or supplement the indenture or the Notes or the Note Guarantees:


	(1) to cure any ambiguity, defect or inconsistency;

	(2) to provide for uncertificated notes in addition to or in place of certificated notes;

	(3) to provide for the assumption of the Company’s or a Guarantor’s obligations to holders of Notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of the Company’s or such Guarantor’s assets, as applicable;

	(4) to make any change that would provide any additional rights or benefits to the holders of Notes or that does not adversely affect the legal rights under the indenture of any such holder;

	(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

	(6) to make, complete or confirm any grant of Collateral permitted or required by the indenture or any of the security documents or any release of Collateral that becomes effective as set forth in the indenture or any of the security documents;

	(7) to conform the text of the indenture, the Note Guarantees, the security documents and/or the Notes to any provision of this Description of the Notes to the extent that such provision in this Description of the Notes was intended to be a verbatim recitation of a provision of the indenture, the Note Guarantees, the security documents or the Notes;

	(8) to provide for the issuance of Additional Notes in accordance with the limitations set forth in the indenture as of the date of the indenture; or

	(9) to allow any Guarantor to execute a supplemental indenture and/or a Note Guarantee with respect to the Notes.

The indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when:


	(a) all Notes that have been authenticated, except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

	(b) all Notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the Notes not delivered to the trustee for cancellation for principal, premium and Special Interest, if any, and accrued interest to the date of maturity or redemption;


	(2) no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) and the deposit will not result in a breach or violation of, or constitute a default under, any


	other instrument to which the Company or any Guarantor is a party or by which the Company or any Guarantor is bound;

	(3) the Company or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

	(4) the Company has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the Notes at maturity or on the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

The Collateral will be released from the Lien securing the Notes, as provided under the caption “— Collateral Trust Agreement — Release of Liens in Respect of Notes,” upon a satisfaction and discharge in accordance with the provisions described above.

If the trustee becomes a creditor of the Company or any Guarantor, the indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

The holders of a majority in aggregate principal amount of the then Outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of Notes, unless such holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.

Anyone who receives this prospectus may obtain a copy of the indenture, the exchange and registration rights agreement, the collateral trust agreement and the security documents without charge by writing to Belden & Blake Corporation, 5200 Stoneham Road, North Canton, Ohio 44720, Attention: Corporate Secretary.

The New Notes will be issued in the form of one or more registered Notes in global form, without interest coupons. Upon issuance, each of the global notes will be deposited with the trustee as custodian for DTC and registered in the name of Cede & Co., as nominee of DTC. Ownership of beneficial interests in each global note will be limited to persons who have accounts with DTC, or DTC participants, or persons who hold interests through DTC participants. We expect that under procedures established by DTC:


	•	upon deposit of each global note with DTC’s custodian, DTC will credit portions of the principal amount of the global note to the accounts of the DTC participants exchanging Outstanding Notes; and


	•	ownership of beneficial interests in each global note will be shown on, and transfer of ownership of those interests will be effected only through, records maintained by DTC (with respect to interests of DTC participants) and the records of DTC participants (with respect to other owners of beneficial interests in the global note.)

Beneficial interests in the global notes may not be exchanged for Notes in physical, certificated form except in the limited circumstances described below.

All interests in the global notes will be subject to the operations and procedures of DTC. We provide the following summaries of those operations and procedures solely for the convenience of investors. The operations and procedures for DTC are controlled by DTC and may be changed at any time. We are not responsible for those operations or procedures.


	•	a limited purpose trust company organized under the laws of the State of New York;

	•	a “banking organization” within the meaning of the New York State Banking Law;

	•	a member of the Federal Reserve System;

	•	a “clearing corporation” within the meaning of the Uniform Commercial Code; and

	•	a “clearing agency” registered under Section 17A of the Exchange Act.

DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between its participants through electronic book-entry changes to the accounts of its participants. DTC’s participants include securities brokers and dealers; banks and trust companies; clearing corporations and other organizations. Indirect access to DTC’s system is also available to others such as banks, brokers, dealers and trust companies; these indirect participants clear through or maintain a custodial relationship with DTC participant, either directly or indirectly. Investors who are not DTC participants may beneficially own securities held by or on behalf of DTC only through DTC participants or indirect participants in DTC.

So long as DTC’s nominee is the registered owner of a global note, that nominee will be considered the sole owner or holder of the Notes represented by that global note for all purposes under the indenture. Except as provided below, owners of beneficial interests in a global note:


	•	will not be entitled to have Notes represented by the global note registered in their names;

	•	will not receive or be entitled to receive physical, certificated Notes; and

	•	will not be considered the owners or holders of the Notes under the indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee under the Indenture.

As a result, each investor who owns a beneficial interest in a global note must rely on the procedures of DTC to exercise any rights of a holder of Notes under the indenture (and, if the investor is not a participant or an indirect participant in DTC, on the procedures of the DTC participant through which the investor owns its interest.)

Payments of principal, premium (if any) and interest with respect to the Notes represented by a global note will be made by the trustee to DTC’s nominee as the registered holder of the global note. Neither we nor the trustee will have any responsibility or liability for the payment of amounts to owners of beneficial interests in a global note, for any aspect of the records relating to or payments made on account of those interests by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those interests.

Payments by participants and indirect participants in DTC to the owners of beneficial interests in a global note will be governed by standing instructions and customary industry practice and will be the responsibility of those participants or indirect participants and DTC.

Transfers between participants in DTC will be effected under DTC’s procedures and will be settled in same-day funds.

DTC has agreed to the above procedures to facilitate transfers of interests in the global notes among participants in those settlement systems. However, DTC is not obligated to perform these procedures and may discontinue or change these procedures at any time. Neither we nor the trustee will have any responsibility for the performance by DTC or its participants or indirect participants of its obligations under the rules and procedures governing its operations.

Notes in physical, certificated form will be issued and delivered to each person that DTC identifies as a beneficial owner of the related Notes only if:


	•	DTC notifies us at any time that it is unwilling or unable to continue as depositary for the global notes and a successor depositary is not appointed within 120 days;

	•	DTC ceases to be registered as a clearing agency under the Securities Exchange Act of 1934 and a successor depositary is not appointed within 120 days;

	•	we, at our option, notify the trustee that we elect to cause the issuance of certificated Notes; or

	•	certain other events provided in the indenture should occur.

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all defined terms used therein, as well as any other capitalized terms used herein for which no definition is provided.

(a) discounted future net revenue from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the Company’s most recently completed fiscal year, which reserve report is prepared or reviewed by independent petroleum engineers, as increased by, as of the date of determination, the discounted future net revenue of


	(i) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

	(ii) estimated crude oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to


	(iii) estimated proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and

	(iv) reductions in the estimated oil and gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

in each case, calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report); provided, however, that, in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Company’s engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material Change which is an increase, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;


	(b) the capitalized costs that are attributable to crude oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements;

	(c) the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

	(d) the greater of (i) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and (ii) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries as of a date no earlier than the date of the Company’s latest audited financial statements (provided that the Company shall not be required to obtain such an appraisal of such assets if no such appraisal has been performed); minus


	(2) to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:


	(a) minority interests;

	(b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

	(c) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

	(d) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to volumetric Production Payments on the schedules specified with respect thereto; and

	(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to dollar-denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (a)(i) (utilizing the same prices utilized in the Company’s year-end reserve report), would be necessary to satisfy fully the obligations of the Company and its


	Restricted Subsidiaries with respect to dollar-denominated Production Payments on the schedules specified with respect thereto.


	(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

	(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.


	(1) prior to the Discharge of Priority Lien Obligations, a direction in writing delivered to the collateral trustee by or with the written consent of the Required Priority Creditors; and

	(2) after the Discharge of Priority Lien Obligations, a direction in writing delivered to the collateral trustee by or with the written consent of the Required Parity Creditors.

For purposes of this definition, (a) Secured Debt registered in the name of, or beneficially owned by, the Company or any Affiliate of the Company will be deemed not to be outstanding, and (b) votes will be determined in accordance with the provisions described above under the caption “— Collateral Trust Agreement — Voting.”

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Applicable Premium” means, with respect to any Note on any redemption date, the greater of:


	(a) the present value at such redemption date of (i) the redemption price of the Note at July 15, 2008 (such redemption price being set forth in the table appearing above under the caption “— Optional Redemption”) plus (ii) all required interest payments due on the Note through July 15, 2008 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 75 basis points; over

	(b) the principal amount of the Note, if greater.


	(1) the sale, lease, conveyance or other disposition of any assets or rights (including, without limitation, any sale of hydrocarbons or other mineral products as a result of the creation of Production Payments and Reserve Sales); provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “— Repurchase at the Option of Holders — Change of Control” and/or the provisions described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

	(2) the issuance of Equity Interests in any of the Company’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:


	(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $1.0 million;

	(2) a transfer of assets between or among the Company and its Restricted Subsidiaries;

	(3) an issuance of Equity Interests by a Restricted Subsidiary of the Company to the Company or to a Restricted Subsidiary of the Company;

	(4) the sale or lease of products, services or accounts receivable in the ordinary course of business and any sale or other disposition of damaged, worn-out or obsolete assets in the ordinary course of business;

	(5) the sale or other disposition of cash or Cash Equivalents;

	(6) a Restricted Payment that does not violate the covenant described above under the caption “— Certain Covenants — Restricted Payments” or a Permitted Investment;

	(7) a disposition of oil, natural gas or other hydrocarbons or other mineral products in the ordinary course of business of the oil and gas production operations of the Company and its Subsidiaries;

	(8) any abandonment, relinquishment, farm-in, farm-out, lease and sublease of developed and/or undeveloped properties made or entered into in the ordinary course of business, but excluding any disposition as a result of the creation of a Production Payment and Reserve Sale; and

	(9) the trade or exchange by the Company or any Restricted Subsidiary of the Company of any oil and gas property or interest therein owned or held by the Company or such Restricted Subsidiary for any oil and gas property or interest therein owned or held by another Person, including any cash or Cash Equivalents necessary in order to achieve an exchange of equivalent value; provided that any such cash or Cash Equivalents received by the Company or such Restricted Subsidiary will be subject to the provisions described in the second, third and fourth paragraphs under the caption “— Repurchase at the Option of Holders — Asset Sales,” which the Board of Directors determines in good faith to be of approximately equivalent value.

“Asset Sale Offer” has the meaning assigned to that term in the indenture governing the Notes.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capital Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capital Lease Obligation.”

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.


	(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;


	(2) with respect to a partnership, the Board of Directors of the general partner of the partnership;

	(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

	(4) with respect to any other Person, the board or committee of such Person serving a similar function.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty.


	(1) in the case of a corporation, corporate stock;

	(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

	(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

	(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock.


	(1) United States dollars;

	(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

	(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

	(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

	(5) commercial paper having one of the two highest ratings obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and, in each case, maturing within six months after the date of acquisition; and

	(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“Casualty Event” means any taking under power of eminent domain or similar proceeding and any insured loss, in each case relating to property or other assets that constituted Collateral.


	(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of the Company and its Subsidiaries taken as a whole to any “person” (as that term is used in Section 13(d) of the Exchange Act) other than a Principal or a Related Party of a Principal;

	(2) the adoption of a plan relating to the liquidation or dissolution of the Company;

	(3) the consummation of any transaction (including, without limitation, any merger or consolidation), the result of which is that any “person” (as defined above), other than the Principals and their Related Parties, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares;

	(4) the Company consolidates with, or merges with or into, any Person, or any Person consolidates with, or merges with or into, the Company, in any such event pursuant to a transaction in which any of the outstanding Voting Stock of the Company or such other Person is converted into or exchanged for cash, securities or other property, other than any such transaction where the Voting Stock of the Company outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (immediately after giving effect to such issuance); or

	(5) after an initial public offering of the Company or any direct or indirect parent of the Company, the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors.

“Change of Control Offer” has the meaning assigned to that term in the indenture governing the Notes.

“Class” means (1) in the case of Parity Lien Debt, every Series of Parity Lien Debt, taken together, and (2) in the case of Priority Lien Debt, every Series of Priority Lien Debt, taken together.

“Collateral” means certain properties and assets at any time owned or acquired by the Company or any of the other Pledgors, including a substantial majority of the aggregate value of our proved producing reserves on a PV-10 basis, and the capital stock of the Company and the Domestic Subsidiaries, except:


	(1) Excluded Assets;

	(2) any properties and assets in which the collateral trustee is required to release its Liens pursuant to the provisions described above under the caption “— Collateral Trust Agreement — Release of Liens on Collateral;” and

	(3) any properties and assets that no longer secure the Notes or any Obligations in respect thereof pursuant to the provisions described above under the caption “— Collateral Trust Agreement — Release of Liens in Respect of Notes,”

provided that, in the case of clauses (2) and (3), if such Liens are required to be released as a result of the sale, transfer or other disposition of any properties or assets of the Company or any other Pledgor, such assets or properties will cease to be excluded from the Collateral if the Company or any other Pledgor thereafter acquires or reacquires such assets or properties.

“collateral trustee” means Wells Fargo Bank, N.A. (as successor by merger to Wells Fargo Bank Minnesota, N.A.), in its capacity as collateral trustee under the collateral trust agreement, together with its successors in such capacity.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:


	(1) an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income; plus

	(2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

	(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

	(4) depreciation, depletion, amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; minus

	(5) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business,

Notwithstanding the preceding, the provision for taxes based on the income or profits of, and the depreciation, depletion and amortization and other non-cash expenses of, a Restricted Subsidiary of the Company will be added to Consolidated Net Income to compute Consolidated Cash Flow of the Company only to the extent that a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior governmental approval (that has not been obtained), and without direct or indirect restriction pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:


	(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

	(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;

	(3) the cumulative effect of a change in accounting principles will be excluded; and

	(4) any write-downs of non-current assets will be excluded; provided, however, that, to the extent they may become applicable, ceiling limitation write-downs in accordance with generally accepted accounting principles shall be treated as capitalized costs, as if such write-down had not occurred; and


	(5) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of FAS 133) will be excluded.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who:


	(1) was a member of such Board of Directors on the date of the indenture; or

	(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Agreement” means that certain Credit and Guaranty Agreement, dated as of July 7, 2004, by and among the Company, Goldman Sachs Credit Partners L.P. and other parties named therein, providing for up to $170.0 million aggregate principal amount of borrowings and the issuance of letters of credit, including any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Credit Agreement Agent” means, at any time, the Person serving at such time as the “Agent” or “Administrative Agent” under the Credit Agreement or any other representative then most recently designated in accordance with the applicable provisions of the Credit Agreement, together with its successors in such capacity.

“Credit Facilities” means, one or more debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities, in each case, with banks or other institutional lenders providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Discharge of Priority Lien Obligations” means the occurrence of all of the following:


	(1) termination or expiration of all commitments to extend credit that would constitute Priority Lien Debt;

	(2) payment in full in cash of the principal of, interest and premium (if any) on, and fees with respect to, all Priority Lien Debt (other than any undrawn letters of credit);

	(3) discharge or cash collateralization (at the lower of (1) 105% of the aggregate undrawn amount and (2) the percentage of the aggregate undrawn amount required for release of liens under the terms of the applicable Priority Lien Document) of all outstanding letters of credit constituting Priority Lien Debt; and

	(4) payment in full in cash of all other Priority Lien Obligations that are outstanding and unpaid at the time the Priority Lien Debt is paid in full in cash (other than any obligations for taxes, costs, indemnifications, reimbursements, damages and other liabilities in respect of which no claim or demand for payment has been made at such time).

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case, at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Company that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

“equally and ratably” means, in reference to sharing of Liens or proceeds thereof as between holders of Secured Obligations within the same Class, that such Liens or proceeds:


	(1) will be allocated and distributed first to the Secured Debt Representative for each outstanding Series of Secured Debt within that Class, for the account of the holders of such Series of Secured Debt, ratably in proportion to the principal of, and interest and premium (if any) and reimbursement obligations (contingent or otherwise) with respect to letters of credit, if any, outstanding (whether or not drawings have been made under such letters of credit) on each outstanding Series of Secured Debt within that Class when the allocation or distribution is made, and thereafter

	(2) will be allocated and distributed (if any remain after payment in full of all of the principal of, and interest and premium (if any) and reimbursement obligations (contingent or otherwise) with respect to letters of credit, if any, outstanding (whether or not drawings have been made on such letters of credit) on all outstanding Secured Obligations within that Class) to the Secured Debt Representative for each outstanding Series of Secured Obligations within that Class, for the account of the holders of any remaining Secured Obligations within that Class, ratably in proportion to the aggregate unpaid amount of such remaining Secured Obligations within that Class due and demanded (with written notice to the applicable Secured Debt Representative and the collateral trustee) prior to the date such distribution is made.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means a public or private offer and sale of Capital Stock (other than Disqualified Stock) of the Company.

(1) any lease, license, contract, general intangible, property right or agreement to which the Company or any other Pledgor is a party or any of its rights or interests thereunder if and only for so long as the grant of a Lien under the security documents will constitute or result in a breach, termination or default under any such lease, license, contract, property right or agreement (other than to the extent that any such term would be rendered ineffective pursuant to Sections 9-406, 9-407, 9-408 or 9-409 of the Uniform Commercial Code of any relevant jurisdiction or any other applicable law or principles of equity); provided that such lease, license, contract, general intangible, property right or agreement will be an Excluded Asset only to the extent and for so long as the consequences specified above will result and will cease to be an Excluded Asset and will become subject to the Lien


	granted under the security documents, immediately and automatically, at such time as such consequences will no longer result;

	(2) real property (other than Hydrocarbon Properties, pipelines and gathering systems) owned or leased by the Company or any other Pledgor to the extent that the lenders under the Credit Agreement and the Hedge Counterparty under the Hedge Agreement do not require such assets to be subject to Liens to secure the Credit Agreement and the Hedge Agreement, respectively;

	(3) all “securities” of any of the Company’s “affiliates” (as the terms “securities” and “affiliates” are used in Rule 3-16 of Regulation S-X under the Securities Act);

	(4) any other property or assets in which a Lien cannot be perfected by the filing of a financing statement under the Uniform Commercial Code of the relevant jurisdiction, so long as the aggregate Fair Market Value of all such property and assets does not at any one time exceed $10.0 million; and

	(5) with respect to all Secured Debt other than Parity Lien Debt consisting of Indebtedness under the Hedge Agreement, the Hedge Letter of Credit issued to or for the benefit of the creditors in respect of Indebtedness under the Hedge Agreement.

“Existing Indebtedness” means Indebtedness of the Company and its Subsidiaries (other than Indebtedness under the Credit Agreement and the Hedge Agreement) in existence on the date of the indenture, until such amounts are repaid.

“Fair Market Value” means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of the Company (unless otherwise provided in the indenture).

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period.


	(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations, or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including any related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect (in accordance with Regulation S-X under the Securities Act) as if they had occurred on the first day of the four-quarter reference period;

	(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

	(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such


	Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

	(4) any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

	(5) any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

	(6) if any Indebtedness bears a floating rate of interest, the interest expense on such Indebtedness will be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligation applicable to such Indebtedness if such Hedging Obligation has a remaining term as at the Calculation Date in excess of 12 months).

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:


	(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates; plus

	(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

	(3) any interest on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

	(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, determined on a consolidated basis in accordance with GAAP;

provided, however that there shall be excluded from Fixed Charges any non-cash amortization or write-off of fees and expenses incurred in connection with the Merger.

“GAAP” means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“Guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise).


	(1) The Canton Oil & Gas Company and Ward Lake Drilling, Inc.; and

	(2) any other Subsidiary of the Company that executes a Note Guarantee in accordance with the provisions of the indenture,

and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

“Hedge Agreement” means the ISDA Master Agreement, dated as of June 30, 2004, with J. Aron & Company that the Company will become a party to effective as of the date of the Merger (including the schedule and credit annex thereto and the confirmations thereunder), pursuant to which the parties thereto have entered into certain gas price swaps, as such Agreement may be amended or assigned from time to time.

“Hedge Counterparty” means J. Aron & Company or any successor under the Hedge Agreement.

“Hedge Letter of Credit” means, collectively, the $40.0 million of letters of credit issued pursuant to the letter credit facility under the Credit Agreement or cash collateral in lieu thereof to support the Hedge Agreement and, $15.0 million of letters of credit issued pursuant to the revolving credit facility under the Credit Agreement; provided that each such hedge letter of credit shall be used by the Company solely to secure the Company’s obligations under the Hedge Agreement and other hedging transactions.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under:


	(1) interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements and interest rate collar agreements;

	(2) other agreements or arrangements designed to manage interest rates or interest rate risk; and

	(3) other agreements or arrangements designed to protect such Person against fluctuations in currency exchange rates or commodity prices including, without limitation, the Hedge Agreement.

“Hedge Outstanding Amount” means, in the case of Parity Lien Obligations arising under hedge agreements, the amount that would be payable in the reasonable judgment of the counterparty under the applicable hedge agreement if such hedge agreement were terminated as the result of an event of default with respect to the Company under such hedge agreement on the business day prior to the date of such determination or, if any hedge agreement was previously terminated, the termination amount which remains unpaid as of the business day preceding such date and, in the case of the Hedge Agreement, only to the extent that the Hedge Letter of Credit is not sufficient to pay such amount.

“Hydrocarbon Properties” means all rights, titles, interests and estates now owned or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee or lease interests farm-ins, farm-outs, overriding royalty and royalty interests, net profit interests, oil payments, production payment interests and similar mineral interests, including any reserved or residual interest of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, condensate, distillate, liquid hydrocarbons, coal bed methane and other gaseous hydrocarbons, all products refined, separated, settled and dehydrated therefrom, including, without limitation, kerosene, liquefied petroleum gas, refined lubricating oils, diesel fuel, drip gasoline, natural gasoline, helium, sulfur and all other minerals.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $100,000 and whose total revenues for the most recent 12-month period do not exceed $100,000; provided that a Restricted Subsidiary will not be considered to be an Immaterial Subsidiary if it, directly or indirectly, guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

“Indebtedness” means, with respect to any specified Person, any indebtedness of such Person (excluding accrued expenses and trade payables), whether or not contingent:


	(1) in respect of borrowed money;

	(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

	(3) in respect of banker’s acceptances;

	(4) representing Capital Lease Obligations or Attributable Debt in respect of sale and leaseback transactions;

	(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

	(6) representing any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit, Attributable Debt and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes (i) all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person and (ii) any warranties or guarantees of production or payment by such Person with respect to any Production Payment or Reserve Sale, but excludes other contractual obligations of such Person with respect to such Production Payment and Reserve Sale.


	(1) any case commenced by or against the Company or any other Pledgor under Title 11, U.S. Code or any similar federal or state law for the relief of debtors, any other proceeding for the reorganization, recapitalization or adjustment or marshalling of the assets or liabilities of the Company or any other Pledgor, any receivership or assignment for the benefit of creditors relating to the Company or any other Pledgor or any similar case or proceeding relative to the Company or any other Pledgor or its creditors, as such, in each case whether or not voluntary;

	(2) any liquidation, dissolution, marshalling of assets or liabilities or other winding up of or relating to the Company or any other Pledgor, in each case whether or not voluntary and whether or not involving bankruptcy or insolvency; or

	(3) any other proceeding of any type or nature in which substantially all claims of creditors of the Company or any other Pledgor are determined and any payment or distribution is or may be made on account of such claims.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of the Company, the Company will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Company’s Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.” The acquisition by the Company or any Subsidiary of the Company of a Person that holds an Investment in a third Person will be deemed to be an Investment by the Company or such Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third

“Investment Grade Rating” means a rating of “BBB-” or higher from Standard & Poor’s Ratings Group (or any successor thereto) and a rating of “Baa3” or higher from Moody’s Investors Service, Inc. (or any successor thereto), as the case may be.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.

(1) as to any Series of Parity Lien Debt, the written agreement of the holders of such Series of Parity Lien Debt, as set forth in the indenture, credit agreement, hedge agreement or other agreement governing such Series of Parity Lien Debt, for the enforceable benefit of all holders of each existing and future Series of Priority Lien Debt, each existing and future Priority Lien Representative and each existing and future holder of Permitted Prior Liens:


	(a) that all Parity Lien Obligations will be and are secured equally and ratably by all Parity Liens at any time granted by the Company or any other Pledgor to secure any Obligations in respect of such Series of Parity Lien Debt, whether or not upon property otherwise constituting collateral for such Series of Parity Lien Debt, and that all such Parity Liens will be enforceable by the collateral trustee for the benefit of all holders of Parity Lien Obligations equally and ratably;

	(b) that the holders of Obligations in respect of such Series of Parity Lien Debt are bound by the provisions of the collateral trust agreement, including the provisions relating to the ranking of Parity Liens and the order of application of proceeds from the enforcement of Parity Liens; and

	(c) consenting to and directing the collateral trustee to perform its obligations under the collateral trust agreement and the other security documents; and

(2) as to any Series of Priority Lien Debt, the written agreement of the holders of such Series of Priority Lien Debt, as set forth in the credit agreement or other agreement governing such Series of Priority Lien Debt, for the enforceable benefit of all holders of each existing and future Series of Parity Lien Debt, each existing and future Parity Lien Representative and each existing and future holder of Permitted Prior Liens:


	(a) that all Priority Lien Obligations will be and are secured equally and ratably by all Priority Liens at any time granted by the Company or any other Pledgor to secure any Obligations in respect of such Series of Priority Lien Debt, whether or not upon property otherwise constituting collateral for such Series of Priority Lien Debt, and that all such Priority Liens will be enforceable by the collateral trustee for the benefit of all holders of Priority Lien Obligations equally and ratably;

	(b) that the holders of Obligations in respect of such Series of Priority Lien Debt are bound by the provisions of the collateral trust agreement, including the provisions relating to the ranking of Priority Liens and the order of application of proceeds from enforcement of Priority Liens; and

	(c) consenting to and directing the collateral trustee to perform its obligations under the collateral trust agreement and the other security documents.

“Management Agreement” means that certain management services agreement, dated as of the date of the indenture, between the Company and the Parent.

“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated future development costs) of more than 25% during a fiscal quarter in the discounted future net revenues from proved crude oil and natural gas reserves of the Company and its Restricted Subsidiaries, calculated in accordance with clause (1)(a) of the definition of ACNTA; provided, however, that the following will be excluded from the calculation of Material Change:


	(1) any acquisitions during the fiscal quarter of oil and gas reserves that have been estimated by independent petroleum engineers and with respect to which a report or reports of such engineers exist; and

	(2) any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the provisions described under the caption “— Repurchase at the Option of Holders — Asset Sales.”

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:


	(1) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and

	(2) any extraordinary gain (but not loss), together with any related provision for taxes on such extraordinary gain (but not loss).

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, and amounts required to be applied to the repayment of Indebtedness, other than Indebtedness under a Credit Facility, secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP.


	(1) all current assets of the Company and its Restricted Subsidiaries; minus

	(2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness;


	(1) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender;

	(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of the Company or any of its Restricted


	Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

	(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries.

“Note Documents” means the indenture, the Notes and the security documents.

“Note Guarantee” means the Guarantee by each Guarantor of the Company’s obligations under the indenture and the Notes, executed pursuant to the provisions of the indenture.

“Obligations” means any principal (including reimbursement obligations with respect to letters of credit whether or not drawn), interest (including all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the Priority Lien Documents, even if such interest is not enforceable, allowable or allowed as a claim in such proceeding), premium (if any), fees, indemnifications, reimbursements, expenses and other liabilities payable under the documentation governing any Indebtedness.


	(1) the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties;

	(2) the gathering, marketing, distribution, treating, processing, storage, selling and transporting of any production from such interests or properties and the marketing of oil and gas obtained from unrelated Persons;

	(3) any business relating to exploration for or development, production, treatment, processing, storage, transportation, gathering or marketing of oil, gas and other minerals and products produced in association therewith;

	(4) any business relating to oilfield sales and service; and

	(5) any activity that is ancillary to or necessary or appropriate for the activities described in clauses (1) through (5) of this definition.

“Parity Lien” means a Lien granted by a security document to the collateral trustee, at any time, upon any property of the Company or any other Pledgor to secure Parity Lien Obligations.


	(1) the Notes issued on the date of the indenture (including any related exchange notes);

	(2) Indebtedness under the Hedge Agreement that was permitted to be incurred and secured under each applicable Secured Debt Document (or as to which the counterparties under the Hedge Agreement obtained an officers’ certificate at the time of incurrence to the effect that such Indebtedness was permitted to be incurred and secured by all applicable Secured Debt Documents);

	(3) Hedging Obligations incurred in the ordinary course of business to hedge or manage fluctuations in commodity prices (other than pursuant to the Hedge Agreement) that is secured equally and ratably with Parity Lien Debt by a Parity Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document;

	(4) any other Indebtedness (including Additional Notes) that is secured equally and ratably with the Parity Lien Debt by a Parity Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document; provided that:


	(a) the net proceeds are used to refund, refinance, replace, defease, discharge or otherwise acquire or retire Priority Lien Debt or other Parity Lien Debt; or


	(b) on the date of incurrence of such Indebtedness, after giving pro forma effect to the incurrence thereof and the application of the proceeds therefrom, the Secured Leverage Ratio would not be greater than 2.75 to 1.0;

provided, in the case of any Indebtedness referred to in clause (3) or (4) above, that:


	(a) on or before the date on which such Indebtedness is incurred by the Company or the applicable Restricted Subsidiary, such Indebtedness is designated by the Company, in an officers’ certificate delivered to each Parity Lien Representative and the collateral trustee, as “Parity Lien Debt” for the purposes of the Secured Debt Documents; provided that no Series of Secured Debt may be designated as both Parity Lien Debt and Priority Lien Debt;

	(b) such Indebtedness is governed by an indenture, credit agreement or other agreement that includes a Lien Sharing and Priority Confirmation; and

	(c) all requirements set forth in the collateral trust agreement as to the confirmation, grant or perfection of the collateral trustee’s Liens to secure such Indebtedness or Obligations in respect thereof are satisfied (and the satisfaction of such requirements and the other provisions of this clause (c) will be conclusively established if the Company delivers to the collateral trustee an officers’ certificate stating that such requirements and other provisions have been satisfied and that such Indebtedness is “Parity Lien Debt”).

“Parity Lien Documents” means, collectively, the Hedge Agreement, the Note Documents, the indenture, credit agreement or other agreement governing each other Series of Parity Lien Debt and the security documents (other than any security documents that do not secure Parity Lien Obligations).

“Parity Lien Obligations” means Parity Lien Debt and all other Obligations in respect thereof.


	(1) in the case of the Notes, the trustee;

	(2) in the case of the Hedge Agreement, the Hedge Counterparty; or

	(3) in the case of any other Series of Parity Debt, the trustee, agent or representative of the holders of such Series of Parity Lien Debt who maintains the transfer register for such Series of Parity Lien Debt and (a) is appointed as a Parity Lien Representative (for purposes related to the administration of the security documents) pursuant to the indenture, credit agreement or other agreement governing such Series of Parity Lien Debt, together with its successors in such capacity, and (b) has become a party to the collateral trust agreement by executing a joinder in the form required under the collateral trust agreement.


	(1) any Investment in the Company or in a Restricted Subsidiary of the Company;

	(2) any Investment in Cash Equivalents;

	(3) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment:


	(a) such Person becomes a Restricted Subsidiary of the Company; or

	(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;


	(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “— Repurchase at the Option of Holders — Asset Sales;”


	(5) any acquisition of assets or Capital Stock solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

	(6) any Investments received in compromise or resolution of (A) obligations of trade creditors or customers that were incurred in the ordinary course of business of the Company or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; or (B) litigation, arbitration or other disputes with Persons who are not Affiliates;

	(7) Investments represented by Hedging Obligations;

	(8) loans or advances to employees made in the ordinary course of business of the Company or the Restricted Subsidiary of the Company in an aggregate principal amount not to exceed $1.0 million at any one time outstanding;

	(9) repurchases of the Notes;

	(10) entry into operating agreements, joint ventures, partnership agreements, limited liability company agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, development agreements, contracts for the sale, transportation or exchange of oil and natural gas, unitization agreements, pooling arrangements, joint bidding agreements, area of mutual interest agreements, production sharing agreements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding however, Investments in corporations other than any Investment received pursuant to the provisions described above under the caption “— Repurchase at the Option of Holders — Asset Sales”; and

	(11) other Investments in any Person other than an Affiliate of the Company having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (11) that are at the time outstanding, not to exceed $15.0 million.


	(1) Liens held by the collateral trustee securing Priority Lien Debt in an aggregate principal amount not exceeding the Priority Lien Cap and all related Priority Lien Obligations;

	(2) Liens held by the collateral trustee equally and ratably securing the Notes to be issued on the date of the indenture, the Notes Guarantees, Indebtedness under the Hedge Agreement and all future Parity Lien Debt and other Parity Lien Obligations;

	(3) Liens in favor of the Company or the Guarantors;

	(4) Liens on property of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Subsidiary of the Company; provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Company or the Subsidiary;

	(5) Liens on property (including Capital Stock) existing at the time of acquisition of the property by the Company or any Subsidiary of the Company; provided that such Liens were in existence prior to, such acquisition, and not incurred in contemplation of, such acquisition;

	(6) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

	(7) Liens existing on the date of the indenture;

	(8) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently


	concluded; provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

	(9) Liens imposed by law, such as carriers’, warehousemen’s, landlord’s and mechanics’ Liens, in each case, incurred in the ordinary course of business;

	(10) survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

	(11) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture;


	(a) the new Lien shall be limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof); and

	(b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;


	(12) Liens on, or related to, properties or assets to secure all or part of the costs incurred in the ordinary course of the Oil and Gas Business for the exploration, drilling, development, production, processing, transportation, marketing, storage or operation thereof;

	(13) Liens on pipeline or pipeline facilities that arise under operation of law;

	(14) Liens arising under operating agreements, joint venture agreements, partnership agreements, mineral leases, processing agreements, oil and gas leases, farm-in agreements, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, gas balancing and other agreements that are customary in the Oil and Gas Business;

	(15) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases;

	(16) Liens securing Production Payments and Reserve Sales; provided that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales and are incurred after the date of the indenture;

	(17) Liens securing Indebtedness incurred to finance the construction, purchase or lease of, or repairs, improvements or additions to, property, plant or equipment of such Person; provided, however that the Lien may not extend to any other property owned by such Person or any of its Restricted Subsidiaries at the time the Lien is incurred (other than assets and property affixed or appurtenant thereto), and such Indebtedness (other than any interest thereon) secured by the Lien may not be incurred more than 180 days after the later of the acquisition, completion of construction, repair, improvement, addition or commencement of full operation of the property subject to the Lien, and such Indebtedness is incurred pursuant to the covenant described above under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;”

	(18) Liens on cash or cash equivalents securing the Hedge Agreement or other hedging transactions to the extent that the sum of such cash or cash equivalents constitutes the proceeds of


	any draw on any letter of credit issued to secure the Hedge Agreement or such hedging transactions; and

	(19) Liens incurred in the ordinary course of business of the Company or any Subsidiary of the Company with respect to obligations that do not exceed $5.0 million at any one time outstanding.


	(1) payments to the Parent in payment of fees not in excess of $1.0 million per annum pursuant to the Management Agreement in accordance with the provisions described under the caption “Certain Covenants — Transactions with Affiliates;

	(2) payments to the Parent to permit the Parent to pay reasonable accounting, legal and administrative expenses of the Parent when due, in an aggregate amount not to exceed $500,000 per annum; and

	(3) for so long as the Company is a member of a group filing a consolidated or combined tax return with the Parent, payments to the Parent in respect of an allocable portion of the tax liabilities of such group that is attributable to the Company and its Subsidiaries (“Tax Payments”). The Tax Payments shall not exceed the lesser of (i) the amount of the relevant tax (including any penalties and interest) that the Company would owe if the Company were filing a separate tax return (or a separate consolidated or combined return with its Subsidiaries that are members of the consolidated or combined group), taking into account any carryovers and carrybacks of tax attributes (such as net operating losses) of the Company and such Subsidiaries from other taxable years and (ii) the net amount of the relevant tax that the Parent actually owes to the appropriate taxing authority. Any Tax Payments received from the Company shall be paid over to the appropriate taxing authority within 30 days of the Parent’s receipt of such Tax Payments or refunded to the Company.


	(1) Liens described in clause (1) of the definition of “Permitted Liens;”

	(2) Liens described in clauses (4), (5), (7), (10), (14), (15) or (16) of the definition of “Permitted Liens;” and

	(3) Permitted Liens that arise by operation of law and are not voluntarily granted, to the extent entitled by law to priority over the Liens created by the security documents.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to renew, refund, refinance, replace, defease or discharge other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:


	(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith);

	(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged;

	(3) if the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged is subordinated in right of payment to the Notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the Notes on terms at least as favorable to the holders of Notes as those contained in the documentation governing the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged; and


	(4) such Indebtedness is incurred either by the Company or by the Restricted Subsidiary who is the obligor on the Indebtedness being renewed, refunded, refinanced, replaced, defeased or discharged.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Pledgors” means the Company, the Guarantors and any other Person (if any) that provides collateral security for any Secured Debt Obligations.

“Principals” means Parent and Carlyle/ Riverstone Global Energy and Power Fund II, L.P.

“Priority Lien” means a Lien granted by a security document to the collateral trustee, at any time, upon any property of the Company or any other Pledgor to secure Priority Lien Obligations.

“Priority Lien Cap” means, as of any date, the principal amount outstanding under the Credit Agreement and/or the Indebtedness outstanding under any other Credit Facility, in an aggregate principal amount not to exceed the sum of the amount provided by clause (1) of the definition of Permitted Debt, as of any date, plus the amount provided by clause (14) of the definition of Permitted Debt, less the amount of Parity Lien Debt incurred after the date of the indenture the net proceeds of which are used to repay Priority Lien Debt. For purposes of this definition, all letters of credit will be valued at the face amount thereof, whether or not drawn and all Hedging Obligations will be valued at zero.


	(1) Indebtedness under the Credit Agreement that was permitted to be incurred and secured under each applicable Secured Debt Document (or as to which the lenders under the Credit Agreement obtained an officers’ certificate at the time of incurrence to the effect that such Indebtedness was permitted to be incurred and secured by all applicable Secured Debt Documents);

	(2) Indebtedness under any other Credit Facility that is secured equally and ratably with the Credit Agreement by a Priority Lien that was permitted to be incurred and so secured under each applicable Secured Debt Document; provided, in the case of any Indebtedness referred to in this clause (2), that:


	(a) on or before the date on which such Indebtedness is incurred by the Company or the applicable Restricted Subsidiary, such Indebtedness is designated by the Company, in an officers’ certificate delivered to each Priority Lien Representative and the collateral trustee, as “Priority Lien Debt” for the purposes of the Secured Debt Documents; provided that no Series of Secured Debt may be designated as both Priority Lien Debt and Parity Lien Debt;

	(b) such Indebtedness is governed by a credit agreement or other agreement that includes a Lien Sharing and Priority Confirmation; and

	(c) all requirements set forth in the collateral trust agreement as to the confirmation, grant or perfection of the collateral trustee’s Lien to secure such Indebtedness or Obligations in respect thereof are satisfied (and the satisfaction of such requirements and the other provisions of this clause (c) will be conclusively established if the Company delivers to the collateral trustee an officers’ certificate stating that such requirements and other provisions have been satisfied and that such Indebtedness is “Priority Lien Debt”); and


	(3) Hedging Obligations incurred to hedge or manage interest rate risk with respect to Priority Lien Debt; provided that:


	(a) such Hedging Obligations are secured by a Priority Lien on all of the assets and properties that secure Indebtedness under the Credit Facility in respect of which such Hedging Obligations are incurred; and

	(b) such Priority Lien is senior to or on a parity with the Priority Liens securing Indebtedness under the Credit Facility in respect of which such Hedging Obligations are incurred.

“Priority Lien Documents” means the Credit Agreement and any other Credit Facility pursuant to which any Priority Lien Debt is incurred and the security documents (other than any security documents that do not secure Priority Lien Obligations).

“Priority Lien Obligations” means Priority Lien Debt and all other Obligations in respect of Priority Lien Debt.

“Priority Lien Representative” means (1) the Credit Agreement Agent or (2) in the case of any other Series of Priority Lien Debt, the trustee, agent or representative of the holders of such Series of Priority Lien Debt who maintains the transfer register for such Series of Priority Lien Debt and is appointed as a representative of the Priority Lien Debt (for purposes related to the administration of the security documents) pursuant to the credit agreement or other agreement governing such Series of Priority Lien Debt.

“Production Payment” means Dollar-Denominated Production Payments and Volumetric Production Payments, collectively.

“Production Payment and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary of the Company to any Person of a royalty, overriding royalty, net profits interest or Production Payment in oil and natural gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where, in the case of each of the foregoing, the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in connection with the transfer of such interests.


	(1) any controlling stockholder, 80% (or more) owned Subsidiary, or immediate family member (in the case of an individual) of any Principal; or

	(2) any trust, corporation, partnership, limited liability company or other entity, the beneficiaries, stockholders, partners, members, owners or Persons beneficially holding an 80% or more controlling interest of which consist of any one or more Principals and/or such other Persons referred to in the immediately preceding clause (1).

“Required Parity Creditors” means, at any time, the holders of more than 50% of the sum of:


	(1) the aggregate outstanding principal amount of Parity Lien Debt (including outstanding letters of credit whether or not then available or drawn);

	(2) other than in connection with the exercise of remedies, the aggregate unfunded commitments to extend credit which, when funded, would constitute Parity Lien Debt; and

	(3) in the case of Parity Lien Obligations arising under hedge agreements, the Hedge Outstanding Amount;

For purposes of this definition, (a) Parity Lien Debt registered in the name of, or beneficially owned by, the Company or any Affiliate of the Company will be deemed not to be outstanding, and (b) votes will be determined in accordance with the provisions described above under the caption “— Collateral Trust Agreement — Voting.”

“Required Priority Creditors” means, at any time, the holders of more than 50% of the sum of:


	(1) the aggregate outstanding principal amount of Priority Lien Debt (including outstanding letters of credit whether or not then available or drawn); and

	(2) other than in connection with the exercise of remedies, the aggregate unfunded commitments to extend credit which, when funded, would constitute Priority Lien Debt.

For purposes of this definition, (a) Priority Lien Debt registered in the name of, or beneficially owned by, the Company or any Affiliate of the Company will be deemed not to be outstanding, and (b) votes will be determined in accordance with the provisions described above under the caption “— Collateral Trust Agreement — Voting.”

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Sale of Collateral” means any Asset Sale involving a sale or other disposition of Collateral.

“Secured Debt Documents” means the Parity Lien Documents and the Priority Lien Documents.

“Secured Debt Representative” means each Parity Lien Representative and each Priority Lien Representative.


	(1) the aggregate principal amount of Secured Debt outstanding on such date (including, without limitation, the Hedge Outstanding Amount under hedge agreements constituting Parity Lien Debt) plus all Indebtedness of Restricted Subsidiaries of the Company that are not Guarantors outstanding on such date (and, for this purpose, letters of credit will be deemed to have a principal amount equal to the face amount thereof, whether or not drawn), to:

	(2) the aggregate amount of the Company’s Consolidated Cash Flow for the most recent four-quarter period for which financial information is available.


	(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations or acquisitions of assets, or any Person or any of its Restricted Subsidiaries acquired by merger, consolidation or the acquisition of all or substantially all of its assets by the specified Person or any of its Restricted Subsidiaries, and including any related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the date on which the event for which the calculation of the Secured Leverage Ratio is made (the “Leverage Calculation Date”) will be given pro forma effect in accordance with Regulation S-X under the Securities Act) as if they had occurred on the first day of the four-quarter reference period;

	(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Leverage Calculation Date will be excluded;

	(3) any Person that is a Restricted Subsidiary on the Leverage Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period; and

	(4) any Person that is not a Restricted Subsidiary on the Leverage Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period.

“Secured Obligations” means Parity Lien Obligations and Priority Lien Obligations.

“Security Documents” means the collateral trust agreement, each Lien Sharing and Priority Confirmation, and all security agreements, pledge agreements, collateral assignments, mortgages, deeds of trust, collateral agency agreements, control agreements or other grants or transfers for security executed and delivered by the Company or any other Pledgor creating (or purporting to create) a Lien upon

“Series of Parity Lien Debt” means, severally, the Notes, the Indebtedness under the Hedge Agreement and each other issue or series of Parity Lien Debt for which a single transfer register is maintained.

“Series of Priority Lien Debt” means, severally, the Indebtedness outstanding under the Credit Agreement and any other Credit Facility that constitutes Priority Lien Debt.

“Series of Secured Debt” means each Series of Parity Lien Debt and each Series of Priority Lien Debt.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the indenture.

“Special Interest” means all liquidated damages owing pursuant to the registration rights agreement.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the date of the indenture, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.


	(1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency and after giving effect to any voting agreement or stockholders’ agreement that effectively transfers voting power) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

	(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof).

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to July 15, 2008; provided, however, that if the period from the redemption date to July 15, 2008 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year will be used.

“Unrestricted Subsidiary” means any Subsidiary of the Company that is designated by the Board of Directors of the Company as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:


	(1) has no Indebtedness other than Non-Recourse Debt;

	(2) except as permitted by the covenant described above under the caption “— Certain Covenants — Transactions with Affiliates,” is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or


	such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company;

	(3) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

	(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of any specified Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:


	(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

	(2) the then outstanding principal amount of such Indebtedness.

The following discussion is a summary of certain federal income tax considerations relevant to the exchange of Outstanding Notes for New Notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of New Notes. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar, or persons who hold the Notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below. We recommend that each holder consult his own tax advisor as to the particular tax consequences of exchanging such holder’s Outstanding Notes for New Notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of Outstanding Notes for New Notes will not be an exchange or otherwise a taxable event to a holder for united states federal income tax purposes. Accordingly, a holder will have the same adjusted issue price, adjusted basis and holding period in the New Notes as it had in the Outstanding Notes immediately before the exchange.

Certain legal matters relating to the validity of the Notes will be passed upon for us by Vinson & Elkins L.L.P.

The consolidated financial statements of Belden & Blake Corporation at December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, appearing in this prospectus and registration statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Ward Lake Drilling, Inc. at December 31, 2003 and 2002, and for each of the three years in the period ended December 31, 2003, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The estimated reserve evaluations and related calculations of Wright & Company, Inc., independent petroleum engineering consultants, included in this prospectus and registration statement have been included and are referenced herein in reliance upon the authority of said firm as experts in petroleum engineering.

We file annual, quarterly and special reports, and other information with the Securities and Exchange Commission, or SEC. You may read and copy any document we file at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. Please call the SEC at 1-888-SEC-0330 for further information on the Public Reference Room. Our SEC filings are also available to the public from the SEC’s web site at www.sec.gov.

You may request a copy of these filings at no cost, by writing or telephoning us at:

If at any time during the two-year period following the later of the date of issue of the New Notes, if any, we are not subject to the information requirements of Section 13 or 15(d) of the Exchange Act, we will furnish to holders of Notes and prospective purchasers thereof the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act in order to permit compliance with Rule 144A in connection with resales of such Notes.

You should rely only upon the information provided in this prospectus. We have not authorized anyone to provide you with different information. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.

The following are definitions of terms commonly used in the oil and natural gas industry and this document.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

Bcfe. One billion cubic feet of natural gas equivalent at standard atmospheric conditions, determined using the ratio of one barrel of oil to six Mcf of natural gas.

Btu. British thermal unit, which is the energy required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Coal Bed Methane (“CBM”). A form of natural gas, predominately methane, which is generated during coal formation and is contained in the coal microstructure.

Capital Expenditures. Investment outlays for exploratory and development drilling (excluding exploratory dry holes); leasehold acquisitions; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which Belden & Blake has a working interest.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe. One thousand cubic feet of natural gas equivalent at standard atmospheric conditions, determined using the ratio of one barrel of oil to six Mcf of natural gas.

Net Acres or Net Wells. A net acre or well is deemed to exist when the sum of Belden & Blake’s fractional ownership working interests in gross acres or wells, as the case may be, equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

Present Value of Future Net Revenues or PV-10. The present value of estimated future net revenues to be generated from the production of proved reserves, net of estimated production and ad valorem taxes, future capital costs and operating expenses, using prices and costs in effect as of the date indicated, without giving effect to federal, state and provincial (foreign) income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The present value reflects the effect of time on the present value of the revenue stream. PV-10 should not be construed as being representative of the fair market value of the properties.

Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Undeveloped Reserves. Reserves that can be expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserve Life. The estimated productive life of a proved reservoir based upon the economic limit of such reservoir producing hydrocarbons in paying quantities assuming certain price and cost parameters. For purposes of this prospectus, reserve life is calculated by dividing the Proved Reserves (on a Mcfe basis) at the end of the period by production volumes for the specified 12 months.

Reserves. Oil and natural gas on a net revenue interest basis, estimated to be commercially recoverable. “Proved developed reserves” include proved developed producing reserves and proved developed behind-pipe reserves. “Proved developed producing reserves” include only those reserves expected to be recovered from existing completion intervals in existing wells. “Proved undeveloped reserves” include those reserves expected to be recovered from new wells on proved undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Undeveloped Acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves.

Working Interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to drill and produce oil and natural gas on the leased acreage and requires the owner to pay their proportionate share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to governmental tax receipts and mineral interest royalties.

All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements.

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 September 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.

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 became our new President and Chief Executive Officer and B. Dee Davis and W. Mac Jensen joined us as Senior Vice Presidents. All of our former directors resigned and Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard were elected to our board of Directors. 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. On December 16, 2004, we accepted the resignations of Frost W. Cochran, David M. Carmichael, B. Dee Davis and W. Mac Jensen from all of their respective positions as officers and directors (as applicable) of the Company and its subsidiaries. Also on December 16, 2004, James A. Winne III became our new Chief Executive Officer and Chairman of the Board of Directors and Michael Becci became our new President and Chief Operating Officer. The size of our Board of Directors is now six.

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 officers of Capital C provide certain management and advisory services to us for a quarterly fee of $250,000. These services included 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 was terminated effective December 20, 2004.

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

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.

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.

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 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.

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 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.

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)

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.

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.

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.

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.

The 8.75% Senior Secured Notes due 2012 are guaranteed, jointly and severally, by the Company’s wholly-owned subsidiaries The Canton Oil & Gas Company and Ward Lake Drilling, Inc. (the “Guarantors”). The consolidating financial information of the Company (the “Issuer”) and it subsidiaries are as follows:

We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation (“Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, shareholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Belden & Blake Corporation at December 31, 2003 and 2002 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2003 the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Asset Retirement Obligations.”

Belden & Blake Corporation (the “Company”) was a privately held company owned by TPG Partners II L.P. (“TPG”) and certain other investors as of December 31, 2003. The Company operates in the oil and gas industry. The Company’s principal business is the production, development, acquisition and marketing and gathering of oil and gas reserves. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural gas has a significant impact on the Company’s working capital and results of operations.

The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform to the presentation in 2003.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company’s financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves. Although actual results could differ from these estimates, significant adjustments to these estimates historically have not been required.

For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less.

Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management’s expectations.

Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.

The Company utilizes the “successful efforts” method of accounting for its oil and gas properties. Under this 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 holes and costs of carrying and retaining unproved properties, are expensed as incurred. 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 such as the complete disposition of a geographical/ geological pool. 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. Impairments recorded in 2003 and 2001 were $475,000 and $179,000, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value. No impairment was recorded in 2002.

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. In performing the review for long-lived asset recoverability during 2003 and 2001, the Company recorded $421,000 and $1.2 million, respectively, of impairments which reduced the book value of producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2002.

On January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 142, “Goodwill and Other Intangible Assets” which was issued in June 2001 by the Financial Accounting Standards Board (FASB). Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life).

At December 31, 2001, the Company had $2.1 million of unamortized goodwill, representing the costs in excess of the net assets of acquired businesses, which was subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $103,000 and $106,000 for the years ended December 31, 2001 and 2000, respectively. The Company assessed the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have a material effect on the Company’s financial position, results of operations or cash flows, including any transitional impairment losses. The Company performed its required transitional impairment test upon adoption of SFAS 142. Due to the Company’s fourth quarter disposition activity, the Company performed its annual impairment test as of December 31, 2002. However, the Company plans to perform its annual impairment test on a recurring basis as of October 1, starting in fiscal 2003.

Intangible assets totaling $5.6 million at December 31, 2003, include $3.9 million of deferred debt issuance costs and $1.4 million of unamortized goodwill. Deferred debt issuance costs are being amortized over their respective terms. At December 31, 2003, the amortization of deferred debt issuance costs in the next five years is as follows: $1.2 million in each of the next two years (2004, and 2005), $1.0 million in 2006 and $403,000 in 2007. During the fourth quarter of 2002, the Company allocated $667,000 of goodwill to disposal transactions.

The Company uses the asset and liability method of accounting for income taxes. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes.

On December 31, 2002, the FASB issued SFAS 148, “Accounting for Stock Based Compensation — Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock Based Compensation” by providing alternative methods of transition to SFAS 123’s fair value method of accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements of SFAS 123. The Company measures 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 by the Company 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.

The fair value of the Company’s stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the years ended December 31, 2003, 2002 and 2001, respectively: risk-free interest rates of 3.7%, 4.1% and 5.0%; volatility factor of the expected market price of the Company’s common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.

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 the Company had applied the fair value provisions of SFAS 123 for the years ended December 31, 2003, 2002 and 2001 were not material.

The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The change in share value in 2003, 2002 and 2001 resulted in an increase in compensation expense of $291,000, $74,000 and $274,000, respectively.

On January 1, 2001, the Company adopted SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” which was issued in June 1998 by the FASB, as amended by SFAS 137, “Accounting for Derivative Instruments and Hedging Activities — Deferral of Effective Date of SFAS 133” and SFAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” issued in June 1999 and June 2000, respectively. SFAS 133, as amended, was applied as the cumulative effect of an accounting change effective January 1, 2001.

As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, 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). Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are 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. See Note 5.

The relationship between the hedging instruments and the hedged items 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. The Company measures effectiveness on changes in the hedge’s intrinsic value. The Company considers these hedges to be highly effective and expects 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. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness at least on a quarterly basis.

Adoption of SFAS 133 on January 1, 2001 resulted in recording a $10.5 million ($6.7 million net of tax) net liability related to the decline in fair value of the Company’s derivative financial instruments with a corresponding reduction in shareholders’ equity to other comprehensive loss. The net liability consisted of $11.8 million in current fair value of derivative liabilities and $1.3 million in current fair value of derivative assets.

On January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $3.8 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.5 million, net of tax, as a cumulative effect of a change in accounting principle in the Company’s consolidated statement of operations in the first quarter of 2003.

A reconciliation of the Company’s liability for plugging and abandonment costs for the year ended December 31, 2003 is as follows (in thousands):

On January 1, 2003, the Company adopted SFAS 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS 145 rescinds SFAS 4, “Reporting Gains and Losses from Extinguishment of Debt,” SFAS 44, “Accounting for Intangible Assets of Motor Carriers” and SFAS 64, “Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements” and amends SFAS No. 13, “Accounting for Leases.” Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in APB 30, “Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions,” now will be used to classify those gains and losses. The adoption of SFAS 145 did not have any effect on the Company’s financial position, results of operations or cash flows.

In June 2002, the FASB issued SFAS 146, “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS 146 was effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on the Company’s financial position, results of operations or cash flows.

In October 2002, the FASB issued SFAS 147, “Acquisitions of Certain Financial Institutions — an amendment of FASB Statements No. 72 and 144 and FASB Interpretation No. 9.” SFAS 147 was effective for the Company for acquisition activities initiated on or after October 1, 2002. The adoption of this standard did not have any effect on the Company’s financial position, results of operations or cash flows.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45’s disclosure requirements are effective for the Company’s interim and annual financial statements for periods ending after December 15, 2002. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair value, which is different from current practice, which is generally to record a liability only when a loss is probable and reasonably estimable. FIN 45 also requires a guarantor to make significant new disclosures, even when the likelihood of making any payments under the guarantee is remote. The adoption of FIN 45 did not have any effect on the Company’s financial statement disclosures, financial position, results of operations or cash flows.

In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company measures expense associated with stock-based compensation using the intrinsic value method prescribed by APB 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized

by the Company 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. The provisions of SFAS 148 were effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARB) 51.” FIN 46 is an interpretation of ARB 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 did not have any effect on the Company’s financial statement disclosures, financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company’s financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS 150, “Accounting for Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer’s own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company’s financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on the Company’s financial position, results of operations or cash flows.

The Company has been 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 is whether SFAS 142 requires 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.”

If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its financial condition, results of operations or cash flows would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company had undeveloped leasehold costs of $5.1 million and $7.6 million at December 31, 2003 and 2002, respectively. The amount of potential balance sheet reclassifications for developed leasehold costs has not been determined.

revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, Employers’ Accounting for Pensions, No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. This Statement retains the disclosure requirements contained in FASB Statement No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits, which it replaces. It requires additional disclosures to those in the original Statement 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. This Statement is effective for financial statements with fiscal years ending after December 15, 2003. The adoption of this standard did not have a material effect on the Company’s financial position, results of operations or cash flows.

In February 2003, the Company purchased reserves in certain wells the Company operates in Michigan for $3.8 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits which the Company entered into in 1996. The Company had the option to purchase these properties beginning in 2003. The Company previously held a production payment on these properties including a 75% reversionary interest in certain future production. The Company purchased those reserve volumes beyond its currently held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf (billion cubic feet) of proved developed producing gas reserves.

On July 11, 2002, the Company acquired net reserves totaling 4.2 Bcfe (billion cubic feet of natural gas equivalent) for a cash payment of $1.2 million. The Company previously held a production payment on these properties through December 31, 2002.

During the second quarter of 2002, the Company acquired the assets of a drilling consulting and frac tank rental business for $1.6 million.

On June 25, 2004, the Company completed a sale of substantially all of its 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 the Company’s 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 the Company’s existing revolving credit facility. As a result of the disposition of the TBR geographical/geological pools, the Company recorded a gain of approximately $46.3 million ($29.5 million net of tax) in June 2004. According to SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of this group of wells is classified as discontinued operations.

In April 2004, the Company decided to dispose of its Arrow Oilfield Service Company (“Arrow”) assets. The Company 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, the Company 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 is classified as discontinued operations.

As a result of the Company’s decision to shift focus away from exploration and development activities in the Knox formation in Ohio, the Company sold substantially all of its undeveloped Knox acreage in Ohio for approximately $2.8 million in September 2003. The sale resulted in a loss of approximately $150,000.

On December 10, 2002, the Company sold 962 oil and natural gas wells in New York and Pennsylvania. The sale included substantially all of the Company’s Medina formation wells in New York and a smaller number of Pennsylvania Medina wells. The properties had approximately 23 Bcfe of total proved reserves. At the time of the sale, the Company’s net production from these wells was approximately 3.9 Mmcfe (million cubic feet of natural gas equivalent) per day (4 Mcfe (thousand cubic feet of natural gas equivalent) per day per well). The Company disposed of these properties due to the low production volume per well and high cost characteristics. The wells sold had proved developed reserves using Securities and Exchange Commission (“SEC”) pricing parameters of approximately 19.4 Bcfe and proved undeveloped reserves of approximately 3.6 Bcfe.

The sale resulted in proceeds of approximately $16.2 million. On December 10, 2002, the Company received $15.5 million in cash with the remaining amount of approximately $700,000 received in February 2003. The proceeds were used to pay down the Company’s revolving credit facility. As a result of the sale, the Company disposed of all of its properties producing from the New York Medina formation. As a result of the disposition of the entire New York Medina geographical/geological pool, the Company recorded a loss on sale of $3.2 million ($1.8 million net of tax) in 2002. According to SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of this group of wells is classified as discontinued operations.

The Company allocates interest expense to operating areas based on the proportionate share of net assets of the area to the Company’s consolidated net assets. The amounts of interest expense allocated to the New York Medina geographical/geological pool and included in income (loss) from discontinued operations for the years ended December 31, 2002 and 2001 were $1.5 million and $1.7 million, respectively.

A transaction fee of $238,000 was paid in 2003 to TPG in connection with the sale. The fee was paid to TPG pursuant to a Transaction Advisory Agreement entered into in 1997 between the Company and TPG.

During 2002, the Company completed the sale of six natural gas compressors in Michigan to a compression services company. The proceeds of approximately $2.0 million were used to pay down the Company’s revolving credit facility. The Company also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors were relocated to maximize compression efficiency. A gain on the sale of $168,000 was deferred and will be amortized as rental expense over the life of the lease.

On August 1, 2002, the Company sold oil and gas properties consisting of 1,138 wells in Ohio that had approximately 10 Bcfe of proved reserves. At the time of the sale, the Company’s net production from these wells was approximately 3.1 Mmcfe per day (3 Mcfe per day per well). The Company disposed of these properties due to the low production volume per well and high operating costs per well. The proceeds of approximately $8.0 million were used to pay down the Company’s revolving credit facility.

From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. The Company employs a policy of hedging gas production sold under New York Mercantile Exchange (“NYMEX”) based contracts by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. At December 31, 2003, the Company’s derivative contracts consisted of natural gas swaps, collars and options. Qualifying NYMEX-based derivative contracts were designated as cash flow hedges. The changes in fair value of non-qualifying derivative contracts will be initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss and will ultimately be reversed within the same line item and included in oil and gas sales over the respective contract terms.

The fair value of derivative assets and liabilities represents the difference between hedged prices and market prices on hedged volumes of natural gas as of December 31, 2003. During 2003, a net loss on contract settlements of $10.3 million ($6.5 million after tax) was reclassified from accumulated other comprehensive income to earnings and the fair value of open hedges decreased by $27.1 million ($17.4 million after tax). At December 31, 2003, the

estimated net losses in accumulated other comprehensive income that are expected to be reclassified into earnings within the next 12 months are approximately $14.6 million. The Company has partially hedged its exposure to the variability in future cash flows through December 2005.

In March 2003, the Company entered into a collar for 4,320 Bbtu (billion British thermal units) of its natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu (million British thermal units) and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle.

In April 2003, the Company entered into a collar for 6,000 Bbtu of its natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle.

On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion British thermal units) of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million that are recognized as increases to natural gas sales revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss).

In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu which qualified and was designated as a cash flow hedge under SFAS 133. The Company also sold a floor at $1.75 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133.

This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options. The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility.

The following table summarizes, as of December 31, 2003, the Company’s net deferred gains on terminated natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains have been recognized as increases to gas sales revenues during the periods in which the underlying forecasted transactions were recognized in net income (loss).

To manage its exposure to natural gas or oil price volatility, the Company may partially hedge its physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options.

The Company’s financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, the Company may modify its fixed price contract and financial hedging positions by entering into new transactions or terminating existing contracts.

The following tables reflect the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) at December 31, 2003:

On October 10, 2002, the Company combined its Pennsylvania/ New York District with its Ohio District to form a new “Appalachian District”. A total of 28 positions were eliminated in the Ohio and Pennsylvania/ New York Districts and in the corporate office. These actions were necessary to capitalize on operational and administrative efficiencies and bring the Company’s employment level in line with anticipated future staffing. The Company recorded a nonrecurring charge of approximately $700,000 in the fourth quarter of 2002 related to severance and other costs associated with these actions.

Effective April 1, 2001, certain senior management members of the Company accepted early retirements. These retirements resulted in a cash charge of approximately $760,000 and an additional non-cash charge of approximately $100,000 related to the acceleration of certain stock options.

The Company recorded a net nonrecurring charge of $2.0 million in 2001 which includes a charge of $2.3 million primarily related to these retirement agreements and other retirement and severance charges incurred which included non-cash charges totaling approximately $200,000 due to the acceleration of certain related stock options. In 2001, the Company recognized approximately $300,000 in other nonrecurring gains.

On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007 (“the Notes”). The Notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The Notes are subordinate to the senior revolving credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer.

The Notes are redeemable in whole or in part at the option of the Company, at any time on or after the dates below, at the redemption prices set forth plus, in each case, accrued and unpaid interest, if any, thereon.

The indenture under which the subordinated notes were issued contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations.

The Company has a $100 million revolving credit facility (the “Revolver”) from Ableco Finance LLC and Wells Fargo Foothill, Inc. (formerly known as Foothill Capital Corporation) which matures on June 30, 2006. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2003, the interest rate was 6.00%. At December 31, 2003, the Company had $38.7 million of outstanding letters of credit. At December 31, 2003, the outstanding balance under the credit agreement was $47.4 million with $38.9 million of borrowing capacity available for general corporate purposes.

During 2002, amendments to the Company’s $100 million revolving credit facility extended the Revolver’s final maturity date to December 31, 2005, from April 22, 2004, increased the letter of credit sub-limit from $30 million to $40 million and permitted the Company to enter into the transactions to sell oil and gas properties consisting of 1,138 wells in Ohio and 962 wells in New York and Pennsylvania.

The Revolver was amended on March 31, 2003 to increase the letter of credit sub-limit to $55 million. On May 30, 2003, the Company amended its $100 million revolving credit facility. The amendment increased the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. The amendment also extended the Revolver’s final maturity date to June 30, 2006,

from December 31, 2005 and permitted the Company to enter into transactions to sell certain oil and gas leases in Ohio in 2003.

The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1 extended through March 31, 2006. The amendment extended the early termination fee, equal to .125% of the Revolver, through June 30, 2005. There is no termination fee after June 30, 2005. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company’s hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through September 2005.

The Revolver, as amended, also contains other financial covenants. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets, excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at least 1.0 to 1 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of December 31, 2003, the Company’s current ratio including the above adjustments was 3.46 to 1. The Company had satisfied all financial covenants as of December 31, 2003.

The Revolver is secured by security interests and mortgages against substantially all of the Company’s assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the value of the Company’s proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company’s proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company’s proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The weighted average price at December 31, 2003, was $4.87 per Mcfe. The present value (using a 10% discount rate) of the Company’s future net income at December 31, 2003, using the borrowing base price forecast was $426 million. The present value under the borrowing base formula above, applying the stated percents of each group of reserves, was approximately $253 million for all proved reserves of the Company and $174 million for properties secured by a mortgage.

From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company’s floating rate exposure is exchanged for a fixed interest rate. There were no interest rate swaps in 2003, 2002 or 2001.

At December 31, 2003, the aggregate long-term debt maturing in the next five years is as follows: $5,000 (2004); $6,000 (2005); $47,412,000 (2006); $225,007,000 (2007) and $78,000 (2008 and thereafter).

The Company leases certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $2.6 million, $2.1 million and $2.4 million for the years ended December 31, 2003, 2002 and 2001, respectively.

The Company also leases certain computer equipment accounted for as capital leases. Property and equipment includes $506,000 and $747,000 of computer equipment under capital leases at December 31, 2003 and 2002, respectively. Accumulated depreciation for such equipment includes approximately $298,000 and $523,000 at December 31, 2003 and 2002, respectively.

Future minimum commitments under leasing arrangements at December 31, 2003 were as follows:

The Company has a 1997 non-qualified stock option plan under which it is authorized to issue up to 1,824,195 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the tenth anniversary of the grant date unless cessation of employment causes earlier termination. As of December 31, 2003, options to purchase 616,321 shares were outstanding under the plan. These options, except for the 100,000 options described below, become exercisable at a rate of one fourth of the shares one year from the date of grant and an additional one twelfth of the remaining shares on every calendar quarter-end thereafter. The remaining 100,000 options become exercisable at a rate of one fourth of the shares on the last day of each quarter commencing June 30, 2003.

During 2002 and 2001, certain employees that retired or were previously terminated elected to put their vested stock options back to the Company. As a result, the Company paid approximately $30,000 and $772,000 to purchase and cancel 13,814 and 219,644 options during 2002 and 2001, respectively.

The weighted average fair value of options granted during 2003, 2002 and 2001 was $0.49, $0.52 and $0.79, respectively. The exercise price for the options outstanding as of December 31, 2003 ranged from $0.01 to $2.14 per share. At December 31, 2003, the weighted average remaining contractual life of the outstanding options is 6.6 years.

The provision (benefit) for income taxes on income from continuing operations before cumulative effect of change in accounting principle includes the following (in thousands):

The effective tax rate for income from continuing operations before cumulative effect of change in accounting principle differs from the U.S. federal statutory tax rate as follows:

During 2001, the Company concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company believes it can fully utilize.

Significant components of deferred income tax liabilities and assets are as follows (in thousands):

SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. The valuation allowance at December 31, 2003 and 2002 relates principally to certain state net operating loss carryforwards which management estimates will expire before they can be utilized.

At December 31, 2003, the Company had approximately $60 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2012 through 2023. The Company has alternative minimum tax credit carryforwards of approximately $900,000 which have no expiration date. The Company has approximately $1.0 million of statutory depletion carryforwards, which have no expiration date.

The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of its Board of Directors based on attainment of performance targets. Amounts are allocated to substantially all employees based on relative compensation. The Company expensed $1.3 million, $1.1 million and $1.4 million for the years ended December 31, 2003, 2002 and 2001, respectively, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash.

As of December 31, 2003, the Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Eligible employees may make voluntary contributions which the Company matches $1.00 for every $1.00 contributed up to 4% of an employee’s annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $433,000, $557,000 and $550,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

Prior to January 1, 2002, the Company matched $0.50 for every $1.00 contributed up to 6% of an employee’s annual compensation on voluntary contributions and an amount equal to 2% of participants’ compensation was contributed by the Company to the plan each year. Effective January 1, 2002, the previous contribution made by the Company in the amount equal to 2% of participants’ compensation each year was eliminated.

In April 2002, the Company was notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. The Company believes there will be no material amount payable above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operation or cash flows.

The Company was audited by the state of West Virginia for the years 1996 through 1998. The state assessed taxes which the Company has contested and filed a petition for reassessment. In February 2003, the Company was notified by the State Tax Commissioner of West Virginia that the Company’s petition for reassessment had been denied and taxes due, plus accrued interest, are now payable. The Company disagrees with the decision and has appealed. The Company believes there will be no material amount payable above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operations or cash flows.

In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. The Company believes the complaint is without merit and is defending the complaint vigorously. Although the outcome is still uncertain, the Company believes the action will not have a material adverse effect on its financial position, results of operations or cash flows. The Company no longer owns the wells that were subject to the suit.

The Company was subject to binding arbitration on an issue regarding the valuation of shares of common stock put back to the Company in 1999 pursuant to a former executive officer’s employment agreement. In March 2003, pursuant to the arbitrator’s ruling, the Company repurchased 31,168 shares of common stock for $337,000 plus

interest from the date of the employment agreement. The Company paid $521,000 in 2003 based on the ruling. The Company recorded the stock purchase as treasury stock in 2002 and expensed the interest in the appropriate periods.

The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.

Environmental costs, if any, are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Expenditures that extend the life of the related property or reduce or prevent future environmental contamination are capitalized. Liabilities related to environmental matters are only recorded when an environmental assessment and/or remediation obligation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. At December 31, 2003, no significant environmental remediation obligation exists which is expected to have a material effect on the Company’s financial position, results of operations or cash flows.

The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $225 million in senior subordinated notes had an approximate fair value of $222.7 million at December 31, 2003 based on quoted market prices.

From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. The Company employs 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 the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. At December 31, 2003, the Company’s derivative contracts consisted of natural gas swaps, collars and options. Qualifying NYMEX-based derivative contracts are designated as cash flow hedges. The Company incurred a pre-tax loss on its hedging activities of $10.3 million in 2003 and pre-tax gains of $21.6 million in 2002 and $4.5 million in 2001. At December 31, 2003, the fair value of futures contracts covering 2004 and 2005 natural gas production represented an unrealized loss of $23.4 million.

The following disclosures of costs incurred related to oil and gas activities are presented in accordance with SFAS 69 and include both continuing and discontinued operations.

The Company’s proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that 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 those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate 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 estimates of proved reserves as of December 31, 2003, 2002 and 2001 have been prepared by Wright & Company, Inc., independent petroleum engineers.

The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated:

The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company’s proved oil and gas reserves. The following assumptions have been made:


	•	Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.


	•	Production and development costs were computed using year-end costs assuming no change in present economic conditions.

	•	Future net cash flows were discounted at an annual rate of 10%.

	•	Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is presented below:

At December 31, 2003, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. The weighted average prices for the total proved reserves at December 31, 2003 were $6.19 per Mcf of natural gas and $29.78 per barrel of oil. The Company does not include its natural gas hedging financial instruments, consisting of natural gas swaps and collars, in the determination of its oil and gas reserves.

The principal sources of changes in the standardized measure of future net cash flows are as follows:

The Company operates 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. The Company’s operations are conducted entirely in the United States.

During 2003 the Company had three customers that each accounted for 10% or more of consolidated revenues with sales of $19.8 million, $11.5 million and $10.8 million, respectively. One customer accounted for more than 10% of consolidated revenues during each of the years ended December 31, 2002 and 2001, sales to which amounted to $12.9 million and $21.0 million, respectively.

The results of operations for the four quarters of 2003 and 2002 are shown below (in thousands).

During 2003, the Company recorded exploratory dry hole expense of approximately $1.1 million, of which $285,000 and $479,000 were incurred in the third and fourth quarters, respectively. In the fourth quarter of 2003, the Company recorded impairments of $475,000 related to unproved properties and $421,000 related to producing properties.

During the fourth quarter of 2002, the Company recorded a loss on sale of $3.2 million ($1.8 million net of tax benefit) from discontinued operations (see Note 4). Sales and gross profit for the first three quarters in 2002 were restated in the fourth quarter of 2002 to reflect the discontinued operations.

During 2002, the Company recorded exploratory dry hole expense of approximately $1.2 million, of which $200,000 was incurred in the fourth quarter.

On March 9, 2004, the Company announced that it had engaged Randall & Dewey Partners, L.P., an oil and gas strategic advisory and consulting firm based in Houston, Texas, to assist the Company in evaluating its strategic alternatives.

We have audited the accompanying balance sheets of Ward Lake Drilling, Inc. (“Company”) as of December 31, 2003 and 2002, and the related statements of operations, parent company investment and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Ward Lake Drilling, Inc. at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the financial statements, in 2003 the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

Ward Lake Drilling, Inc. (the “Company”) is a wholly owned subsidiary of Belden & Blake Corporation (the “Parent”). The Company operates in the oil and gas industry primarily in Michigan. The Company’s principal business is the production, development, acquisition and gathering of oil and gas reserves. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers. The price of oil and natural gas has a significant impact on the Company’s working capital and results of operations.

The financial statements include certain adjustments and allocations of indirect operating expenses such as the Parent’s corporate accounting, corporate land, corporate engineering and the Senior Vice President of Operations. These costs include salaries and benefits as well as other administrative costs and are allocated based on the estimated time spent on the Company’s activity. Allocation percentages are reviewed and adjusted annually. Corporate expense related to the other executive officers or the corporate legal, treasury, human resources, information technology, internal audit, tax or financial reporting departments is not allocated. The Company records its direct costs related to these functions. Management believes that this is a reasonable method for allocating these general and administrative corporate expenses. The allocation is not necessarily representative of the operating expenses that would have been incurred had the Company operated on a stand-alone basis for the periods presented, nor is it representative of the costs expected to be incurred in subsequent periods.

The Parent company investment account represents its equity investment in the Company. Interest expense associated with the Parent’s corporate debt was allocated to the Company based on its proportional share of the Parent’s total assets. The Parent’s corporate debt has not been allocated to the Company. The Company received funding for its operations from the Parent as deemed necessary. All cash and non-cash transfers to and from the Parent have been reported in the Parent company investment account.

The Parent’s 8.75% Senior Secured Notes due 2012 are guaranteed, jointly and severally, by the Parent’s wholly-owned subsidiaries The Canton Oil & Gas Company and Ward Lake Drilling, Inc.

For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less.

Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.

The Company utilizes the “successful efforts” method of accounting for its oil and gas properties. Under this 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 holes and costs of carrying and retaining unproved properties, are expensed as incurred. 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 such as the complete disposition of a geographical/geological pool. 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.

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

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. In performing the review for long-lived asset recoverability during 2003, the Company recorded $421,000 of impairments which reduced the book value of producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2002 and 2001.

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

The Company’s operations have been included in the consolidated income tax returns filed by the Parent. Income tax expense in the statement of operations is calculated on a separate tax return basis as if the Company was a separate taxpayer.

On December 31, 2002, the FASB issued SFAS 148, “Accounting for Stock Based Compensation — Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock Based Compensation” by providing alternative methods of transition to SFAS 123’s fair value method of accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements of SFAS 123. The Company’s Parent measures 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. No adjustments to compensation expense were required in 2003, 2002 and 2001.

The fair value of the Parent’s stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the years ended December 31, 2003, 2002 and 2001, respectively: risk-free interest rates of 3.7%, 4.1% and 5.0%; volatility factor of the expected market price of the Parent’s common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Parent’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.

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 the Company had applied the fair value provisions of SFAS 123 for the years ended December 31, 2003, 2002 and 2001 were not material.

On January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $410,000 increase in long-term asset retirement obligation liabilities, a $294,000 increase in the carrying value of oil and gas assets, a $402,000 decrease in accumulated depreciation, depletion and amortization and a $113,000 increase in deferred income tax liabilities. The net effect of adoption was

to record a gain of $172,000, net of tax, as a cumulative effect of a change in accounting principle in the Company’s statement of operations in the first quarter of 2003.

Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma net income for the years ended December 31, 2002 and 2001 was a net loss of $266,000 and net income of $2.8 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $286,000.

A reconciliation of the Company’s liability for plugging and abandonment costs for the year ended December 31, 2003 is as follows (in thousands):

In December 2002, the FASB issued SFAS 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” SFAS 148 amends FASB 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company measures expense associated with stock-based compensation using the intrinsic value method prescribed by APB 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized by the Company 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. The provisions of SFAS 148 were effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In April 2003, the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company’s financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In May 2003, the FASB issued SFAS 150, “Accounting for Financial Instruments with Characteristics of both Liabilities and Equity.” This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer’s own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company’s financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on the Company’s financial position, results of operations or cash flows.

In 2003, the Company was 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 Task Force 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. As the Company already includes these assets as part of its capitalized oil and gas properties, the application of this FSP will not have an impact on the Company.

In December 2003, the FASB issued SFAS 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” an amendment of SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises employers’ disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, Employers’ Accounting for Pensions, No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions. This Statement retains the disclosure requirements contained in FASB Statement No. 132, Employers’ Disclosures about Pensions and Other Postretirement Benefits, which it replaces. It requires additional disclosures to those in the original Statement 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. This Statement is effective for financial statements with fiscal years ending after December 15, 2003. The adoption of this standard did not have a material effect on the Company’s financial position, results of operations or cash flows.

During 2002, the Company completed the sale of six natural gas compressors in Michigan to a compression services company. The proceeds of approximately $2.0 million were used to pay down the Parent’s revolving credit facility. The Company also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors were relocated to maximize compression efficiency. A gain on the sale of $168,000 was deferred and will be amortized as a reduction of rental expense over the life of the lease.

The Company leases certain natural gas compressors, equipment, vehicles and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $2.0 million, $1.6 million and $1.5 million for the years ended December 31, 2003, 2002 and 2001, respectively. The Company had no capital leases at December 31, 2003. Future minimum commitments under operating lease arrangements at December 31, 2003 were as follows: $2.6 million (2004); $2.2 million (2005); $2.2 million (2006); $1.8 million (2007) and $135,000 (2008 and thereafter).

The provision (benefit) for income taxes before cumulative effect of change in accounting principle includes the following (in thousands):

The effective tax rate for income before cumulative effect of change in accounting principle differs from the U.S. federal statutory tax rate as follows:

Significant components of deferred income tax liabilities and assets are as follows (in thousands):

The Company’s employees participate in the Parent’s non-qualified profit sharing arrangement under which the Parent contributes discretionary amounts determined by the compensation committee of the Parent’s Board of Directors based on attainment of performance targets. Amounts are allocated to substantially all employees based on

relative compensation. The Company expensed $129,000, $90,000 and $169,000 for the years ended December 31, 2003, 2002 and 2001, respectively, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash.

The Company’s employees also participate in the Parent’s qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Eligible employees may make voluntary contributions which is matched $1.00 for every $1.00 contributed up to 4% of an employee’s annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $82,000, $93,000 and $104,000 for the years ended December 31, 2003, 2002 and 2001, respectively.

Prior to January 1, 2002, $0.50 for every $1.00 contributed up to 6% of an employee’s annual compensation on voluntary contributions and an amount equal to 2% of participants’ compensation was contributed by the Parent to the plan each year. Effective January 1, 2002, the previous contribution made by the Parent in the amount equal to 2% of participants’ compensation each year was eliminated.

The following disclosures of costs incurred related to oil and gas activities are presented in accordance with SFAS 69 and include both continuing and discontinued operations.

The Company’s proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that 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 those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate 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 Company’s estimates of proved reserves are derived from the Parent’s estimates of proved reserves as of December 31, 2003, 2002 and 2001 which were prepared by Wright & Company, Inc., independent petroleum engineers.

The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated:


	•	Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.

	•	Production and development costs were computed using year-end costs assuming no change in present economic conditions.

	•	Future net cash flows were discounted at an annual rate of 10%.

	•	Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is presented below:

At December 31, 2003, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. The weighted average prices for the total proved reserves at December 31, 2003 were $6.04 per Mcf of natural gas and $29.84 per barrel of oil. The Company does not include its natural gas hedging financial instruments, consisting of natural gas swaps and collars, in the determination of its oil and gas reserves.

The principal sources of changes in the standardized measure of future net cash flows are as follows:

During 2003 the Company had three customers that each accounted for 10% or more of revenues with sales of $19.8 million, $6.9 million and $4.4 million, respectively. During 2002 the Company had three customers that each accounted for 10% or more of revenues with sales of $10.2 million, $5.8 million and $5.0 million, respectively. During 2001 the Company had four customers that each accounted for 10% or more of revenues with sales of $10.3 million, $8.2 million, $5.8 million and $4.0 million, respectively.

The results of operations for the four quarters of 2003 and 2002 are shown below (in thousands).

During 2003, the Company recorded exploratory dry hole expense of approximately $718,000, of which $371,000 was incurred in the fourth quarter. In the fourth quarter of 2003, the Company recorded impairments of $421,000 related to producing properties.

During 2002, the Company recorded exploratory dry hole expense of approximately $864,000, of which $517,000 and $347,000 were incurred in the third and fourth quarters, respectively.

Unless the context requires otherwise or unless otherwise noted, when we use the terms “Ward Lake,” “we,” “us,” “our” or the “Company,” we are referring to Ward Lake Drilling, Inc. Ward Lake is a wholly owned subsidiary of Belden & Blake Corporation (the “Parent”). On July 7, 2004, the Parent, 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 Parent (the “Merger”), with the Parent surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Parent.

The table below summarizes the Company’s portion of 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.

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

The accompanying unaudited 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 to July 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 the Parent’s annual report on Form 10-K for the year ended December 31, 2003. Certain reclassifications have been made to conform to the current presentation.

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.

The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The predecessor company did not have stock-based compensation expense in the 183 day period from January 1, 2004 to July 1, 2004 or the nine months ended September 30, 2003. The successor company does not have any stock-based compensation expense.


		As of September 30, 2004

		(in thousands)
Cash and cash equivalents		$	25,949

Current portion of long-term debt			1,006
Long-term debt, net of current maturities:
	Senior Facilities		98,750
	Senior Secured Notes		192,500
Other long-term debt			93

Total debt			292,349
Shareholders’ equity:
	Common stock, without par value; authorized 1,500 shares; issued 1,500 shares
Paid in capital			77,500
Deficit			(2,304	)
Accumulated other comprehensive loss			(22,723	)

Total shareholders’ equity			52,473

Total capitalization		$	344,822


Special Note Regarding Forward-Looking Statements		ii
Summary		1
Risk Factors		15
The Exchange Offer		28
Use of Proceeds		38
Capitalization		39
Unaudited Pro Forma Consolidated Financial Statements		40
Selected Historical Financial Data		45
Management’s Discussion and Analysis of Financial Condition and Results of Operations		47
Business and Properties		69
Management and Directors		82
Description of the Collateral		88
Description of Other Indebtedness		89
Description of the Notes		93
Certain United States Federal Income Tax Considerations		154
Legal Matters		154
Experts		154
Available Information		154
Glossary of Oil and Gas Terms		156


(1)	The TBR properties accounted for approximately 5 Bcfe of estimated proved reserves as of December 31, 2003. We did not have proved reserves attributable to these properties prior to 2003. We sold our interests, or rights to our interests, in these properties in June 2004.

(2)	The weighted average year-end prices used for purposes of estimating our proved reserves and future net revenues were $6.19 per Mcf of natural gas and $29.78 per barrel of oil at December 31, 2003, $4.99 per Mcf of natural gas and $27.81 per barrel of oil at December 31, 2002, and $2.92 per Mcf of natural gas and $17.85 per barrel of oil at December 31, 2001. These prices did not include the anticipated effect of our hedging financial instruments.

(3)	Please read the discussion on Page 1 relating to our December 31, 2004 proved reserves estimate.


	*Hedging transactions may limit our potential gains or expose us to loss.*


	*Our operations require large amounts of capital that may not be recovered or raised.*


	*Oil and natural gas prices are volatile, and an extended decline in prices would hurt our profitability and financial condition.*


	*If oil and natural gas prices decrease or our drilling efforts are unsuccessful, we may be required to write down the carrying value of our oil and natural gas properties.*


	*Information concerning our reserves and future net revenues is uncertain.*


	*Our exploitation and development drilling activities may not be successful.*


	*We face strong competition in the oil and natural gas industry, and the resources of many of our competitors are greater than ours.*


	*Our operations are subject to the business and financial risk of oil and natural gas exploration.*


	*Our business is subject to operating hazards that could result in substantial losses.*


	*We must comply with complex federal, state and local laws and regulations.*


	*We may incur substantial costs to comply with stringent environmental regulations.*


	*Our business depends on gathering and transportation facilities owned by others.*


	*All of our common stock is owned by one controlling shareholder whose interests may differ from those of the holders of our Notes.*


	If you do not properly tender your Outstanding Notes, you will continue to hold unregistered Outstanding Notes and your ability to transfer Outstanding Notes will remain restricted and may be adversely affected.


	We may incur substantial additional debt, which could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the Notes.


	*The holders of the Notes may not be able to realize fully the value of the liens securing the Notes.*


	The lien ranking and voting provisions set forth in the indenture and the collateral trust agreement substantially limit the rights of the holders of the Notes with respect to the collateral securing the Notes.


	*The potential environmental liability of secured lenders may affect the value of the collateral for the Notes.*


	*Tendering Through DTC’s Automated Tender Offer Program*


		Historical		Pro Forma			Pro Forma
		2004		Adjustments			2004

Revenues
	Oil and gas sales	$	66,975	$	—		$	66,975
	Gas gathering and marketing		7,236					7,236
	Other		1,008					1,008

			75,219		—			75,219
Expenses
	Production expense		16,451					16,451
	Production taxes		1,950					1,950
	Gas gathering and marketing		6,559					6,559
	Exploration expense		4,051					4,051
	General and administrative expense		3,600					3,600
	Franchise, property and other taxes		182					182
	Depreciation, depletion and amortization		17,700		8,463	(a)		26,163
	Accretion expense		329		150	(b)		479
	Derivative fair value (gain) loss		5,826					5,826

			56,648		8,613			65,261

Operating income			18,571		(8,613	)		9,958
Other expense
	Interest expense		18,327		(1,424	)(c)		16,903

Income (loss) from continuing operations before income taxes			244		(7,189	)		(6,945	)
	Provision (benefit) for income taxes		111		(3,264	)(d)		(3,153	)

Income (loss) from continuing operations		$	133	$	(3,925	)	$	(3,792	)



			Three months
			ended				Nine months ended
			September 30,				September 30,				Year ended December 31,

			2004		2003		2004		2003		2003		2002		2001

Production:
	Natural gas (Mmcf)			3,795		3,832		11,492		10,857		14,834		15,882		17,164
	Oil (Mbbl)			93		103		282		306		413		522		644
		Natural gas equivalents (Mmcfe)		4,355		4,452		13,183		12,694		17,311		19,012		21,030
Average price(1):
	Natural gas (per Mcf)		$	4.87	$	4.87	$	5.00	$	4.94	$	4.92	$	4.95	$	4.35
	Oil (per Bbl)			34.28		27.57		33.73		28.07		28.06		22.72		23.04
	Natural gas equivalents (per Mcfe)			4.98		4.83		5.08		4.90		4.89		4.76		4.26
Average costs (per Mcfe):
	Production expense		$	1.26	$	1.12	$	1.25	$	1.13	$	1.16	$	1.07	$	1.01
	Production taxes			0.15		0.14		0.15		0.15		0.14		0.09		0.11
	Depletion			1.83		0.80		1.16		0.79		0.85		0.87		0.91
Operating margin (per Mcfe)(2)				3.57		3.57		3.68		3.62	$	3.59	$	3.60	$	3.14



					Natural Gas Collars

	Natural Gas Swaps						NYMEX		Crude Oil Swaps
							Price
			NYMEX Price				per Mmbtu		Estimated		NYMEX
Quarter Ending	Bbtu		per Mmbtu		Bbtu		Floor/Cap(1)		Mbbls		Price per Bbl

December 31, 2004		2,040	$	3.81		1,080	$	4.00 - 5.76		74	$	35.68

		2,040	$	3.81		1,080	$	4.00 - 5.76		74	$	35.68

March 31, 2005		1,500	$	3.81		1,500	$	4.00 - 5.32		68	$	34.76
June 30, 2005		1,500		3.70		1,500		4.00 - 5.32		68		34.18
September 30, 2005		1,500		3.70		1,500		4.00 - 5.32		67		33.72
December 31, 2005		1,500		3.70		1,500		4.00 - 5.32		67		33.31

		6,000	$	3.73		6,000	$	4.00 - 5.32		270	$	34.00

March 31, 2006		2,829	$	6.14						63	$	32.71
June 30, 2006		2,829		5.24						62		32.35
September 30, 2006		2,829		5.22						62		32.02
December 31, 2006		2,829		5.39						62		31.71

		11,316	$	5.50						249	$	32.20

Year Ending


December 31, 2007		10,745	$	4.97						227	$	30.91
December 31, 2008		10,126		4.64						208		29.96
December 31, 2009		9,529		4.43						191		29.34
December 31, 2010		8,938		4.28						175		28.86
December 31, 2011		8,231		4.19						157		28.77
December 31, 2012		7,005		4.09						138		28.70
December 31, 2013		6,528		4.04						127		28.70


Bbl — Barrel		Mmbtu — Million British thermal units
Mbbls — Thousand barrels		Bbtu — Billion British thermal units



	Payment Due by Period

Contractual Obligations at			Less Than
December 31, 2003	Total		1 Year		1-3 Years		4-5 Years		After 5 Years


	(in thousands)
Long-term debt	$	272,508	$	5	$	47,418	$	225,015	$	70
Capital lease obligations		208		100		71		37		—
Operating leases		10,784		3,465		5,180		2,139		—

Total contractual cash obligations	$	283,500	$	3,570	$	52,669	$	227,191	$	70


Asset retirement obligation, December 31, 2002		$	—
	Cumulative effect adjustment		4,387
	Liabilities incurred		268
	Liabilities settled		(471	)
	Accretion expense		344
	Revisions in estimated cash flows		67

Asset retirement obligation, December 31, 2003		$	4,595


				Range of Average Drilling and
		Range of Well Depths		Completion Costs per Well

		(in feet)		(in thousands)
Ohio:
	Clinton		3,000- 5,500	$	180- 220
Pennsylvania:
	Coal Bed Methane		1,200- 1,500		160- 190
	Clarendon		1,100- 2,000		70- 85
	Medina		5,000- 6,200		230- 280
Michigan:
	Antrim		700- 2,000		170- 230



								Deeper or Less
		Highly Developed						Developed
		Formations(1)						Formations(2)

		2001		2002		2003		2001			2002		2003

Productive:
	Gross		142.0		83.0		79.0		14.0	(3)		12.0		9.0
	Net		130.6		63.7		74.2		7.4			6.2		4.9
Dry:
	Gross		3.0		1.0		—		16.0			16.0		10.0
	Net		3.0		0.9		—		8.0			8.4		7.3



	As of December 31, 2003


	Gas Wells				Oil Wells				Total

State	Gross		Net		Gross		Net		Gross		Net

Ohio		939		764		875		807		1,814		1,571
Pennsylvania		701		570		461		460		1,162		1,030
New York		27		17		—		—		27		17
Michigan		1,116		533		7		4		1,123		537

		2,783		1,884		1,343		1,271		4,126		3,155