Filed pursuant to Rule 424(b)(3)
Registration No. 333-134748

Prospectus

Offer to Exchange Up to

$325,000,000 of 8 ¹/2% Senior Notes Due 2015

that have been registered under the Securities Act of 1933

for

$325,000,000 of 8 ¹/2% Senior Notes Due 2015

that have not been registered under the Securities Act of 1933

THE EXCHANGE OFFER WILL EXPIRE AT 5:00 PM, NEW YORK

CITY TIME, ON AUGUST 18, 2006, UNLESS WE EXTEND THE DATE

Terms of the Exchange Offer:

• We are offering to exchange up to $325.0 million aggregate principal amount of registered 8 ¹/2% Senior Notes due 2015, which we refer to as the new notes, for any and all of our $325.0 million aggregate principal amount of unregistered 8 ¹/2% Senior Notes due 2015, which we refer to as the old notes, that were issued on December 1, 2005.

• We will exchange all outstanding old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.

• The terms of the new notes are substantially identical to those of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

• You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes will not be a taxable transaction for U.S. federal income tax purposes.

• We will not receive any cash proceeds from the exchange offer.

• The old notes are, and the new notes will be, guaranteed on a senior unsecured basis by all of our current and future domestic restricted subsidiaries.

• There is no established trading market for the new notes or the old notes.

• We do not intend to apply for listing of the new notes on any national securities exchange or for quotation through any quotation system.

See “ Risk factors” beginning on page 22 for a discussion of certain risks that you should consider prior to tendering your outstanding old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of distribution.”

July 19, 2006

Table of contents

	Page
Special cautionary statement regarding forward-looking statements	ii
Prospectus summary	1
Risk factors	22
Ratio of earnings to fixed charges	36
Use of proceeds	37
Capitalization	38
Unaudited pro forma financial data	39
Selected consolidated financial data	42
Management’s discussion and analysis of financial condition and results of operations	44
Business and properties	60
Management	80
Principal stockholders	87
Certain relationships and related transactions	88
Description of certain indebtedness	90
The exchange offer	92
Description of the new notes	105
Global securities; book-entry system	167
Material United States federal income tax considerations	171
Plan of distribution	172
Legal matters	173
Experts	173
Independent petroleum engineers	173
Where you can find more information	173
Glossary of terms	A-1
Index to financial statements	F-1

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC. In making your decision to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus, or the documents incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document incorporated by reference, as the case may be.

THIS PROSPECTUS INCORPORATES IMPORTANT BUSINESS AND FINANCIAL INFORMATION ABOUT OUR COMPANY THAT HAS NOT BEEN INCLUDED IN OR DELIVERED WITH THIS PROSPECTUS. WE WILL PROVIDE WITHOUT CHARGE TO EACH PERSON TO WHOM THIS PROSPECTUS IS DELIVERED, UPON WRITTEN OR ORAL REQUEST, A COPY OF ANY SUCH INFORMATION. REQUESTS FOR SUCH COPIES SHOULD BE DIRECTED TO: CHIEF FINANCIAL OFFICER, CHAPARRAL ENERGY, INC., 701 CEDAR LAKE BOULEVARD, OKLAHOMA CITY, OKLAHOMA 73114; TELEPHONE NUMBER: (405) 478-8770. TO OBTAIN TIMELY DELIVERY, YOU SHOULD REQUEST THE DOCUMENTS AND INFORMATION NO LATER THAN AUGUST 18, 2006.

i

Special cautionary statement regarding forward-looking statements

This prospectus includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. Forward-looking statements include information concerning possible or assumed future results of operations of us and our affiliates. These statements may relate to, but are not limited to, information or assumptions about capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of our senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements.

Forward-looking statements may relate to various financial and operational matters, including, among other things:

• fluctuations in demand or the prices received for our oil and natural gas;

• whether or not we consummate an initial public offering of our common stock, or any other issuances of our equity, and the amount of net proceeds to us, if any, therefrom;

• the amount, nature and timing of capital expenditures;

• drilling of wells;

• competition and government regulations;

• timing and amount of future production of oil and natural gas;

• costs of exploiting and developing our properties and conducting other operations, in the aggregate and on a per unit equivalent basis;

• increases in proved reserves;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• estimates of proved reserves;

• exploitation or property acquisitions;

• marketing of oil and natural gas; and

• general economic conditions and the other risks and uncertainties discussed in this prospectus.

Undue reliance should not be placed on forward-looking statements, which speak only as of the date of this prospectus.

A description of certain risks relating to us and our business appears under the heading “Risk factors” beginning on page 22 of this prospectus.

All subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements

ii

contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this document or to reflect the occurrence of unanticipated events, unless the securities laws require us to do so.

Industry and market data

The market data and other statistical information used throughout this prospectus are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including the U.S. Department of Energy. Some data are also based on our good faith estimates. Although we believe these third-party sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

iii

Prospectus summary

This summary highlights information contained elsewhere in this prospectus. Because this section is only a summary, it does not contain all of the information that may be important to you or that you should consider before making a decision to participate in the exchange offer. We encourage you to read this entire prospectus, including the information contained under the heading “Risk factors.” You should read the following summary together with the more detailed information, pro forma financial information and consolidated financial information and the notes thereto included elsewhere in this prospectus. In this prospectus, unless the context otherwise requires, the terms “Chaparral,” “Company,” “we,” “us” and “our” refer to Chaparral Energy, Inc. and its predecessor, Chaparral L.L.C., and its subsidiaries.

In this prospectus, “pro forma basis” means after giving pro forma effect to (1) our acquisition of the 99% limited partner interest in CEI Bristol Acquisition, L.P. on September 30, 2005, (2) the issuance of $325.0 million aggregate principal amount of our 8 ¹/2% Senior Notes due 2015 on December 1, 2005 and (3) the application of the net proceeds from the issuance of the notes. See “—Recent developments” and “Use of proceeds.” This prospectus does not give effect to a stock split that would be effected as a stock dividend if we complete the initial public offering of our common stock prior to completion of the exchange offer contemplated by this prospectus. Investors who are not familiar with oil and gas industry terms used in this prospectus should refer to the “Glossary of terms” section set forth in this prospectus.

Our business

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to development drilling. As of December 31, 2005, approximately 84% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties.

As of December 31, 2005, we had estimated proved reserves of 618 Bcfe (69% proved developed and 67% natural gas) and a PV-10 value of $1.6 billion. For the year ended December 31, 2005, on a pro forma basis, our average daily production was 81 MMcfe. For the three months ended March 31, 2006, our average daily production was 83 MMcfe, a 34% increase over the same period in 2005. As of December 31, 2005, our estimated pro forma reserve life was 20.9 years. For the year ended December 31, 2005, on a pro forma basis, our revenues were $150.0 million. For the three months ended March 31, 2006, our revenues were $60.1 million. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value, beginning on page 19.

For the period from 2002 to 2005, our proved reserves and production have grown at a compounded annual growth rate of 35% and 26%, respectively. We have grown primarily through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

1

Our capital expenditures for oil and gas properties for the year ended December 31, 2005 were $333.0 million, representing a 247% increase over the prior year. Excluding $152.9 million recorded for the oil and gas properties acquired as part of the CEI Bristol acquisition, our capital expenditures in 2005 for oil and gas properties were $180.1 million, representing an 88% increase over the prior year. Our 2006 capital expenditure budget for oil and gas properties is $210.0 million assuming we receive net proceeds of at least $139.0 million from the issuance of our equity during 2006. We have budgeted approximately 62% of our 2006 capital expenditures on development activities (drilling—43%, enhancements—11% and tertiary recovery—8%), 33% for acquisitions and 5% for exploration activities. The majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO₂) tertiary recovery projects in the Mid-Continent and Permian Basin.

The following table presents proved reserves and PV-10 value as of December 31, 2005, and average daily production for the year ended December 31, 2005 and the three months ended March 31, 2006 by our areas of operation.

	Proved reserves as of December 31, 2005						Average daily production (MMcfe per day)	Pro forma average daily production (MMcfe per day)	Average daily production (MMcfe per day)
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	Percent of total MMcfe	PV-10 value ($mm)		Year ended December 31, 2005	Year ended December 31, 2005	Three months ended March 31, 2006
Mid-Continent	20,752	285,994	410,506	66.5%	$	1,070.0	48.2	55.4	53.2
Permian Basin	6,057	73,347	109,689	17.8%		265.3	7.8	9.3	9.9
East Texas	1,257	26,059	33,601	5.4%		90.5	7.4	8.3	10.4
North Texas	2,239	3,977	17,411	2.8%		48.5	2.1	2.5	2.5
Rocky Mountains	1,916	4,245	15,741	2.5%		37.4	2.0	2.5	2.5
Gulf Coast	1,692	20,762	30,914	5.0%		90.9	2.0	3.0	4.3
Total	33,913	414,384	617,862	100.0%	$	1,602.6	69.5	81.0	82.8

Business strengths

Consistent track record of low-cost reserve additions and production growth.    From 2002 to 2005, we have grown reserves and production by a compounded annual growth rate of 35% and 26%, respectively. We have achieved this through a combination of drilling success and acquisitions. We replaced approximately 468%, 794% and 822% of our production in 2003, 2004 and 2005, respectively, at an average fully developed FD&A cost of $1.82 per Mcfe over this three year period, which we believe is among the lowest in the industry.

Disciplined approach to acquisitions.    We have a dedicated team that conducts due diligence, including reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. In 2003, 2004 and 2005, our capital expenditures for acquisitions were $19.9 million,

2

$30.5 million and $222.3 million, respectively. These acquisition capital expenditures represented approximately 35%, 32% and 67%, respectively, of our total capital expenditures for those years. On September 30, 2005, we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added an estimated 115 Bcfe of proved reserves as of that date. Excluding the acquisition of CEI Bristol, we spent $69.3 million on acquisitions during 2005, representing approximately 39% of our total capital expenditures. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

Property enhancement expertise.    Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation of coiled tubing or siphon string, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.

Inventory of drilling locations.    As of December 31, 2005, we had an inventory of over 790 proved developmental drilling locations and over 2,100 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our 2005 drilling rate, as shown in the following table.

	Identified proved undeveloped drilling locations	Identified other potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net
Mid-Continent	653	1,440	295,482	33,524
Permian Basin	81	470	49,915	11,718
East Texas	4	34	30,219	1,352
North Texas	30	146	16,349	2,924
Rocky Mountains	14	25	10,025	7,286
Gulf Coast	11	12	25,399	6,775
Total	793	2,127	427,389	63,579

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 22. We spent $87.3 million on development and exploration drilling for 2005. We have experienced a high historical drilling success rate of approximately 96% on a weighted average basis during 2003, 2004 and 2005. For 2006, we have budgeted $102.0 million to drill more than 80 operated wells and to participate in more than 130 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO₂ enhanced oil recovery. CO₂ enhanced oil recovery involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers

3

that have substantial expertise in CO₂ tertiary recovery operations, as well as specific software for modeling CO₂ enhanced recovery. We own a 29.2% interest in and operate a large CO₂ tertiary flood unit in southern Oklahoma and installed and operate a second tertiary flood unit with a 54% interest in the Oklahoma panhandle. At December 31, 2005, our proved reserves included four properties where CO₂ tertiary recovery methods are used, which comprise approximately 9% of our total proved reserves.

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 34 years after starting his career at Exxon as a petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 22 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Joe Evans, our Chief Financial Officer, has over 27 years of experience in the oil and gas industry. Individuals in our 24-person management team have an average of over 25 years of experience in the oil and gas industry.

Business strategy

We seek to grow reserves and production profitably through a balanced mix of developmental drilling, acquisitions, enhancements, tertiary oil recovery projects and a modest number of exploration projects. Further, we strive to control our operations and costs and to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:

Continue lower-risk development drilling program.    We have allocated $91.0 million, or 43% of our 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. Our 2006 acquisition capital budget is $70.0 million, or 33% of our total capital expenditure budget.

Apply technical expertise to enhance mature properties.    Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 13 field offices throughout Oklahoma, Texas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor. As of December 31, 2005, we had an inventory of 227 developed enhancement projects requiring total estimated capital expenditures of $16.3 million.

4

Expand CO₂ enhanced oil recovery activities.    We have accumulated interests in 43 properties in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in certain of these properties. We plan to expand our Camrick CO₂ project in 2006 and initiate CO₂ injection in our NW Camrick and Perryton Units in 2007. We have budgeted $16 million in 2006 towards these projects. To support our existing CO₂ tertiary recovery projects, we currently inject approximately 37 MMcf per day of CO₂. We have a 100% ownership interest in our 86 mile Borger CO₂ pipeline, a 29% interest in the 120 mile Enid to Purdy CO₂ pipeline, and a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline.

Pursue modest exploration program.    In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $11.0 million, or approximately 5% of our 2006 capital expenditures, on exploration activities.

Control operations and costs.    We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancement, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and gas production to maximize both volumes and wellhead price. As of December 31, 2005, we operated properties comprising approximately 79% of our proved reserves.

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of March 31, 2006, we had hedges in place for approximately 69%, 59% and 19% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 74%, 72% and 44% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities of $12.2 million, $21.4 million and $68.3 million for the years ended December 31, 2003, 2004 and 2005, respectively, as commodity prices have increased.

Recent developments

Initial Public Offering of Common Stock.    We have filed a registration statement on Form S-1 in connection with the initial public offering of our common stock. We may or may not complete that offering prior to the completion of this exchange offer, or at all. We have not yet determined the aggregate number of shares that may be issued by us in connection with the initial public offering, and accordingly cannot predict the amount, if any, of net proceeds to us.

Acquisition of CEI Bristol Acquisition, L.P.    On September 30, 2005, we acquired the limited partner interest in CEI Bristol Acquisition, L.P. from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. Total consideration paid by us, including costs associated with the settlement of all previously existing hedge positions by CEI Bristol, was approximately $158 million. Prior to this acquisition, we held a 1% general partner interest through our wholly-owned subsidiary Chaparral Oil, L.L.C. and TIFD III-X LLC held a 99% limited partner interest in CEI Bristol. Chaparral Oil, L.L.C. also managed CEI Bristol and its properties since 2000.

5

CEI Bristol’s properties were located primarily in the Mid-Continent and Permian Basin areas. As of September 30, 2005, CEI Bristol had estimated proved reserves of 115 Bcfe, resulting in an acquisition price based on the total consideration paid by us for the reserves of approximately $1.34 per Mcfe. During the nine months ended September 30, 2005, CEI Bristol produced 4.2 Bcfe at an average daily production rate of 15.7 MMcfe. For the nine months ended September 30, 2005, CEI Bristol had oil and gas sales of $29.8 million and net income of $2.6 million. We expect the acquisition to increase our production in 2006 by approximately 4.8 Bcfe.

Oklahoma Ethanol L.L.C.    In August 2005, we entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma Farmers Union Sustainable Energy LLC to construct and operate an ethanol production plant in Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of ethanol, 176,000 tons of distillers dried grains and 2.8 Bcfe of CO₂ per year. We will have the option to acquire all or part of this CO₂ for use in our tertiary oil recovery projects. The start up and construction costs are estimated to be between $90 million and $95 million, with Chaparral currently having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $54 million to $57 million in secured indebtedness with recourse limited to our interests in this entity to fund construction costs and for related start-up working capital. We expect to enter into a construction contract in 2006 and expect construction to commence in late 2006 or early 2007 with completion in 2008, and that our equity contribution will be approximately $24 million to $25.3 million.

Risk factors

Our business and our business strategy are subject to a number of material risks described in “Risk factors” beginning on page 22, including:

• volatility of oil and gas prices;

• writedowns of the carrying values of our properties;

• risks inherent in estimating reserves;

• our leverage and ability to borrow future funds;

• competition for acquisitions;

• demand for oil field equipment, services and qualified personnel;

• changes in laws and regulations; and

• losses from hedging obligations.

You should consider carefully these and other risks described in “Risk factors” before deciding to participate in the exchange offer.

Chaparral Energy, Inc. is a Delaware corporation. Our principal executive offices are located at 701 Cedar Lake Boulevard, Oklahoma City, OK 73114 and our telephone number at that address is (405) 478-8770. Our web site is located at http://www.chaparralenergy.com. The information on our web site is not part of this prospectus.

6

Ownership Structure

The following chart shows our organization and ownership structure as of the date of this prospectus.

(1) This entity will not be a restricted subsidiary or guarantor of the notes. Chaparral Energy, L.L.C. owns a 66.67% membership interest in Oklahoma Ethanol L.L.C. Oklahomans for Sustainable Energy owns the remaining membership interest in this joint venture.

7

Ratio of earnings to fixed charges

The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year Ended December 31,					Three Months Ended March 31, 2006
	2001	2002	2003	2004	2005
Ratio of earnings to fixed charges	3.6x	3.1x	5.3x	5.4x	2.3x	2.8x

The ratio was computed by dividing earnings by fixed charges. For this purpose, “earnings” represent the aggregate of pre-tax income from continuing operations before cumulative effect of accounting change plus fixed charges excluding capitalized interest. “Fixed charges” include interest expensed, capitalized interest and amortization of debt issuance costs.

8

The exchange offer

On December 1, 2005, we completed a private offering of the old notes. As part of the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes in which we agreed, among other things, to deliver this prospectus to you and to use our commercially reasonable efforts to complete the exchange offer within 270 days of the issue date of the old notes. The following is a summary of the exchange offer.

Old Notes 8 ¹/2% Senior Notes due December 1, 2015, which were issued on December 1, 2005.

New Notes 8 ¹/2% Senior Notes due December 1, 2015. The terms of the new notes are substantially identical to those terms of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

Exchange Offer We are offering to exchange up to $325.0 million aggregate principal amount of our new notes that have been registered under the Securities Act for an equal amount of our outstanding old notes that have not been registered under the Securities Act to satisfy our obligations under the registration rights agreement.

The new notes will evidence the same debt as the old notes and will be issued under and be entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter rights in connection with the exchange offer. Because the new notes will be registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer will have no registration rights.

Expiration Date The exchange offer will expire at 5:00 p.m., New York City time, on August 18, 2006, unless we decide to extend it.

Conditions to the Exchange Offer The exchange offer is subject to customary conditions, which we may waive. Please read “The exchange offer—Conditions to the exchange offer” for more information regarding the conditions to the exchange offer.

Procedures for Tendering Old Notes Unless you comply with the procedures described under the caption “The exchange offer—Procedures for tendering—Guaranteed delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:

• tender your old notes by sending the certificates for your old notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to Wells Fargo

9

Bank, National Association, as registrar and exchange agent, at the address listed under the caption “The exchange offer—Exchange agent”; or

• tender your old notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your old notes in the exchange offer, Wells Fargo Bank, National Association, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your old notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The exchange offer—Procedures for tendering—Book-entry transfer.”

Guaranteed Delivery Procedures If you are a registered holder of the old notes and wish to tender your old notes in the exchange offer, but

• the old notes are not immediately available,

• time will not permit your old notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or

• the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,

then you may tender old notes by following the procedures described under the caption “The exchange offer—Procedures for tendering—Guaranteed delivery.”

Special Procedures for Beneficial Owners If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes in the exchange offer, you should promptly contact the person in whose name the old notes are registered and instruct that person to tender on your behalf.

If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your old notes, you must either make appropriate arrangements to register ownership of the old notes in your name or obtain a properly completed bond power from the person in whose name the old notes are registered.

10

Withdrawal; Non-Acceptance You may withdraw any old notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on August 18, 2006. If we decide for any reason not to accept any old notes tendered for exchange, the old notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted old notes will be credited to the tendering holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered old notes, please read “The exchange offer—Withdrawal rights.”

U.S. Federal Income Tax Considerations We believe the exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read the discussion under the caption “Material United States federal income tax considerations” for more information regarding the tax consequences to you of the exchange offer.

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 the registration rights agreement.

Fees and Expenses We will pay all of our expenses incident to the exchange offer.

Exchange Agent We have appointed Wells Fargo Bank, National Association as exchange agent for the exchange offer. You can find the address, telephone number and fax number of the exchange agent under the caption “The exchange offer—Exchange agent.”

Resales of New Notes Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the new notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:

• the new notes are being acquired in the ordinary course of business;

• you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer;

• you are not our affiliate; and

• you are not a broker-dealer tendering old notes acquired directly from us for your account.

11

The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”

Please read “The exchange offer—Resales of new notes” for more information regarding resales of the new notes.

Consequences of Not Exchanging Your Old Notes If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register your old notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer your old notes unless we have registered the old notes under the Securities Act, 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.

For information regarding the consequences of not tendering your old notes and our obligation to file a registration statement, please read “The exchange offer—Consequences of failure to exchange outstanding securities” and “Description of the new notes.”

Exchange agent Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

WELLS FARGO BANK, NATIONAL ASSOCIATION

By Facsimile for Eligible Institutions: (214) 777-4086, Attention: Ms. Nancye Patterson

By Mail/Overnight Delivery/Hand: Wells Fargo Bank, National Association, 1445 Ross Ave., 2nd Floor, Dallas, Texas 75202, Attention: Ms. Nancye Patterson

Confirm By Telephone: (214) 777-4078

12

Description of the new notes

The terms of the new notes and those of the outstanding old notes are substantially identical, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. As a result, the new notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and special interest provisions contained in the old notes. The new notes represent the same debt as the old notes for which they are being exchanged. Both the old notes and the new notes are governed by the same indenture.

The following summary contains basic information about the notes and is not intended to be complete. For a more complete understanding of the notes, please refer to the section in this prospectus entitled “Description of the new notes.”

Issuer Chaparral Energy, Inc.

Securities offered $325,000,000 aggregate principal amount of 8 ¹/2% Senior Notes due 2015.

Maturity date December 1, 2015.

Interest payment

dates Interest on the new notes will accrue at the rate of 8 ¹/2% per year and will be payable semi–annually on June 1 and December 1 of each year, beginning June 1, 2006.

Guarantees Each of our restricted subsidiaries will unconditionally guarantee the notes on a senior unsecured basis. At the time of issuance, Oklahoma Ethanol L.L.C. will be an unrestricted subsidiary and each of our other subsidiaries will be restricted subsidiaries.

Ranking The notes will be our senior unsecured obligations and will:

• rank equally in right of payment with all of our existing and future senior debt;

• rank senior to all of our existing and future subordinated debt;

• be effectively subordinated to all of our existing and future secured obligations to the extent of the value of the assets securing such obligations, including indebtedness under our senior secured credit facility; and

• be structurally subordinated to all debt and other obligations of our non-guarantor subsidiaries.

Similarly, the guarantees by our subsidiary guarantors will:

• rank equally in right of payment with all of the existing and future senior debt of such subsidiary guarantors;

• rank senior to all of the existing and future subordinated debt of such subsidiary guarantors;

13

• be effectively subordinated to all of the existing and future secured obligations of such subsidiary guarantors to the extent of the value of the assets securing such obligations, including guarantees under our senior secured credit facility; and

• be structurally subordinated to all debt and other obligations of our non-guarantor subsidiaries.

As of March 31, 2006, the notes were effectively subordinated to $134.0 million of senior secured debt, and we would have had $37.5 million of additional borrowing capacity available for additional secured borrowings or letters of credit under our senior secured credit facility.

Optional redemption We may redeem some or all of the notes at any time on or after December 1, 2010. We may also redeem up to 35% of the aggregate principal amount of the notes using the proceeds from certain equity offerings completed before December 1, 2008. In addition, we may redeem the notes, in whole or in part, at any time prior to December 1, 2010 at a redemption price plus an applicable premium. The redemption prices and applicable premium are described under “Description of the new notes—Optional redemption.”

Change of control and asset sales If we experience specific kinds of changes of control, we will be required to make an offer to purchase the notes at a purchase price of 101% of the principal amount thereof, plus accrued and unpaid interest to the purchase date. See “Description of the new notes—Change of control.”

If we sell assets under certain circumstances, we will be required to make an offer to purchase the notes at their face amount, plus accrued and unpaid interest to the purchase date. See “Description of the new notes—Repurchase at the option of holders—Asset sales.”

Certain covenants The indenture restricts our ability and the ability of our restricted subsidiaries to, among other things:

• incur additional indebtedness;

• make certain distributions, investments and other restricted payments;

• create certain liens;

• merge, consolidate or sell substantially all of our assets;

• enter into transactions with affiliates;

• sell assets; and

• limit the ability of restricted subsidiaries to make payments to us.

14

These covenants will be subject to important qualifications, which are described under the heading “Description of the new notes—Certain covenants.”

15

Summary consolidated historical and

pro forma financial data

You should read the following summary consolidated historical and pro forma financial information in connection with the financial statements and related notes included in this prospectus, and the “Management’s discussion and analysis of financial condition and results of operations” beginning on page 44 and the “Unaudited pro forma financial data” beginning on page 39 of this prospectus. The historical consolidated financial data for each of the three fiscal years ended December 31, 2005 (except for balance sheet data as of December 31, 2003) were derived from our audited annual financial statements included in this prospectus. The data for the three months ended March 31, 2005 and 2006 were derived from our unaudited interim consolidated financial statements appearing in this prospectus. In the opinion of management, this three-month data includes all normal recurring adjustments necessary for a fair statement of the results for those interim periods. Our summary historical results are not necessarily indicative of results to be expected in future periods.

The acquisition of CEI Bristol occurred on September 30, 2005, and the accounts of CEI Bristol are included in our consolidated historical balance sheet as of December 31, 2005. The results of operations of CEI Bristol are included in our consolidated statements of operations subsequent to September 30, 2005.

The summary pro forma financial data for the fiscal year ended December 31, 2005 gives effect to the following transactions:

• our acquisition of the limited partner interest in CEI Bristol, including hedge settlement costs; and

• our issuance of $325.0 million aggregate principal amount of our 8 ¹/2% Senior Notes on December 1, 2005 and the application of net proceeds.

The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2005 assumes the pro forma transactions described above all occurred on January 1, 2005.

16

	Year ended December 31,
	Historical									Pro forma
(Dollars in thousands)	2003			2004			2005			2005 (unaudited)
Operating results data:
Revenues
Oil and gas sales	$	74,186		$	113,546		$	201,410		$	231,183
Loss on oil and gas hedging activities		(12,220	)		(21,350	)		(68,324	)		(81,160	)
Total revenues		61,966			92,196			133,086			150,023
Costs and expenses
Lease operating		19,520			26,928			42,147			48,321
Production taxes		4,840			8,272			14,626			17,084
Depreciation, depletion and amortization		10,376			17,533			31,423			37,941
General and administrative		4,946			5,985			9,808			10,697
Total costs and expenses		39,682			58,718			98,004			114,043
Operating income		22,284			33,478			35,082			35,980
Non-operating income (expense)
Interest expense		(4,116	)		(6,162	)		(15,588	)		(33,105	)
Other income		208			279			665			682
Net non-operating expense		(3,908	)		(5,883	)		(14,923	)		(32,423	)
Income before income taxes and accounting change		18,376			27,595			20,159			3,557
Income tax expense		6,932			9,880			7,309			1,290
Income before accounting change		11,444			17,715			12,850			2,267
Cumulative effect of change in accounting principle, net of income taxes		(887	)		—			—			—
Net income	$	10,557		$	17,715		$	12,850		$	2,267
Cash flow data:
Net cash provided by operating activities	$	32,541		$	49,849		$	65,111
Net cash used in investing activities		(55,213	)		(95,120	)		(334,435	)
Net cash provided by financing activities		26,146			54,061			257,080
	As of December 31,
	Historical
	2003			2004			2005
Financial position data:
Cash and cash equivalents	$	5,052		$	13,842		$	1,598
Total assets		211,086			308,827			647,379
Total debt		118,355			176,622			446,544
Undistributed/retained earnings		30,977			48,692			58,133
Accumulated other comprehensive loss, net of income taxes		(4,900	)		(12,107	)		(47,967	)
Total equity		26,078			36,586			10,167

17

	Three months ended March 31,
(Dollars in thousands)	2005 (unaudited)			2006 (unaudited)
Operating results data:
Revenue
Oil and gas sales	$	36,149		$	61,295
Loss on oil and gas hedging activities		(8,839	)		(1,153	)
Total revenues		27,310			60,142
Costs and expenses
Lease operating		8,636			15,133
Production taxes		2,651			4,658
Depreciation, depletion and amortization		6,251			11,053
General and administrative		2,300			3,405
Total costs and expenses		19,838			34,249
Operating income		7,472			25,893
Non-operating income (expense)
Interest expense		(2,345	)		(9,165	)
Other income		173			104
Net non-operating expenses		(2,172	)		(9,061	)
Income before income taxes		5,300			16,832
Income tax expense		2,037			6,460
Net income	$	3,263		$	10,372
Cash flow data:
Net cash provided by operating activities	$	18,336		$	29,020
Net cash used in investing activities		(34,149	)		(47,044	)
Net cash provided by financing activities		9,913			24,902
	As of March 31, 2006
	(unaudited)
Financial position data:
Cash and cash equivalents	$	8,476
Total assets		682,476
Total debt		472,025
Undistributed/retained earnings		68,155
Accumulated other comprehensive loss, net of income taxes		(32,146	)
Total equity		36,010

18

Non-GAAP financial measures and reconciliations

PV-10 Value

The PV-10 value (PV-10) is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at December 31, 2005 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 as of December 31, 2005 for our major areas of operation.

(Dollars in millions)	PV-10 value		Present value of future income tax discounted at 10%		Standardized measure of discounted future net cash flows
Mid Continent	$	1,070.0	$	357.0	$	713.0
Permian Basin		265.3		88.5		176.8
East Texas		90.5		30.2		60.3
North Texas		48.5		16.2		32.3
Rocky Mountains		37.4		12.5		24.9
Gulf Coast		90.9		30.3		60.6
Total	$	1,602.6	$	534.7	$	1,067.9

19

Summary reserve information

The following table summarizes our estimates of net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates (using prices in effect on December 31, 2003, 2004 and 2005), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2003 were prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Estimates of our net proved oil and natural gas reserves as of December 31, 2004 and 2005 were prepared by Cawley, Gillespie and Associates, Inc. (80% of PV-10 value in 2005) and Lee Keeling & Associates, Inc. (4% of PV-10 value in 2005), both independent petroleum engineering firms, and our engineering staff (16% of PV-10 value in 2005).

All proved reserve estimates were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission, based on the price differentials received on a property-by-property basis as of December 31 of each year. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for unproved acreage. The proved reserve estimates represent our net revenue interest in our properties.

	As of December 31,
	2003		2004		2005
Proved reserves
Oil (Mbbl)		16,777		28,585		33,913
Natural gas (MMcf)		203,677		263,620		414,384
Natural gas equivalent (MMcfe)		304,339		435,130		617,862
Proved developed reserves percentage		81%		67%		69%
PV-10 value (in thousands)	$	488,305	$	775,116	$	1,602,610
Estimated reserve life (in years)(1)		19.9		22.9		24.4
Cost incurred (in thousands):
Property acquisition costs(2)	$	19,864	$	30,546	$	222,285
Development costs		36,758		62,371		103,479
Exploration costs		340		3,114		7,274
Total	$	56,962	$	96,031	$	333,038
Annual reserve replacement ratio(3)		468%		794%		822%
Three-year average fully developed FD&A cost ($/Mcfe)(4)			$	1.21	$	1.82

(1) Calculated by dividing net proved reserves by net production volumes for the year indicated.

(2) Includes $152,945 of costs related to the acquisition of CEI Bristol in 2005.

(3) Calculated by dividing the sum of reserve additions from all sources (revisions, extensions and discoveries, improved recoveries, and acquisitions) by the production for the corresponding period.

(4) Calculated as total costs incurred, plus the increase in future development costs, divided by total proved reserve acquisitions, extensions and discoveries, and revisions as shown below:

	2002		2003		2004		2005
Purchases of minerals in place		48,819		50,515		62,238		173,176
Extensions and discoveries		3,689		12,766		34,004		22,531
Revisions		24,295		102		14,535		(7,516	)
Improved recoveries		623		8,202		39,722		20,262
Total reserve additions		77,426		71,585		150,499		208,453
Costs incurred	$	40,852	$	56,962	$	96,031	$	333,038
Changes in future development costs		25,268		20,494		121,938		154,042
Total costs incurred	$	66,120	$	77,456	$	217,969	$	487,080
Three-year average fully developed FD&A cost ($/Mcfe)					$	1.21	$	1.82

20

Summary production and sales data

The following table sets forth certain information regarding our net production volumes, sales, average prices realized, and production costs associated with sales of oil and natural gas for the periods indicated.

	Year ended December 31,						Three months ended March 31,
	2003		2004		2005		2005		2006
Net production volumes
Oil (MBbls)		924		1,173		1,449		321		431
Natural gas (MMcf)		9,762		11,923		16,660		3,648		4,868
Combined (MMcfe)		15,306		18,961		25,354		5,574		7,454
Oil and gas sales ($ in thousands)(1)
Oil	$	27,643	$	47,537	$	77,899	$	15,218	$	25,760
Natural gas		46,543		66,009		123,511		20,931		35,535
Total	$	74,186	$	113,546	$	201,410	$	36,149	$	61,295
Oil average sales price (per Bbl)
Price excluding hedges	$	29.92	$	40.53	$	53.76	$	47.41	$	59.77
Price including hedges	$	26.70	$	29.16	$	36.43	$	33.55	$	41.45
Natural gas average sales price (per Mcf)
Price excluding hedges	$	4.77	$	5.54	$	7.41	$	5.74	$	7.30
Price including hedges	$	3.82	$	4.86	$	4.82	$	4.53	$	8.68
Average production cost and production taxes (per Mcfe)
Average production cost(2)	$	1.28	$	1.42	$	1.66	$	1.55	$	2.03
Average production taxes(3)	$	0.32	$	0.44	$	0.58	$	0.48	$	0.62

(1) Does not include the effect of oil and gas hedging activities.

(2) Our production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the administrative costs of field offices, insurance and gas handling charges.

(3) Includes severance and ad valorem taxes.

21

Risk factors

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to participate in the exchange offer. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. The risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially adversely affect our business, financial condition or results of operations. When we use the term “notes” in this prospectus, unless the context requires otherwise, the term includes the old notes, the previously issued notes and the new notes.

Risks related to the exchange offer and the new notes

If you do not properly tender your old notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. Please read “The exchange offer—Procedures for tendering” and “Description of the new notes.”

If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of tendering your old notes in the exchange offer, please read “The exchange offer—Consequences of failure to exchange outstanding securities.”

You may find it difficult to sell your new notes.

Although the new notes will trade in The PORTAL^SM Market and will be registered under the Securities Act, the new notes will not be listed on any securities exchange. Because there is no public market for the new notes, you may not be able to resell them.

We cannot assure you that an active market will exist for the new notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of our new notes may be adversely affected. If a market for the new notes develops, they may trade at a discount from their initial offering price. The trading market for the notes may be adversely affected by:

• changes in the overall market for non-investment grade securities;

• changes in our financial performance or prospects;

• the financial performance or prospects for companies in our industry generally;

• the number of holders of the notes;

• changes in the credit ratings assigned by independent rating agencies;

• the interest of securities dealers in making a market for the notes; and

• prevailing interest rates and general economic conditions.

22

Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

Some holders who exchange their old notes may be deemed to be underwriters.

If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Risks related to our business

Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of our cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include:

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

• commodity processing, gathering and transportation availability, and the availability of refining capacity;

• the price and level of foreign imports of oil and natural gas;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• financial and commercial market uncertainty;

• political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and

• worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on

23

our financial condition, results of operations and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our 8 ¹/2% Senior Notes, or make planned capital expenditures.

We could incur a write-down of the carrying values of our properties in the future depending on oil and natural gas prices, which could negatively impact our net income and stockholder’s equity.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the unit-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for oil and natural gas at that date as adjusted for our cash flow hedge positions. A significant decline in oil and natural gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our tertiary recovery operations. Reserve estimates are, therefore, inherently imprecise and, although we believe that we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results most likely will vary from our estimates. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions could cause the estimated quantities and net present value of our reserves to differ materially. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses from the development and production of oil and gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the Commission, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 2005 PV-10 value uses realized prices based on a Henry Hub spot price of $10.08 per MMBtu for natural gas and a WTI Cushing spot price of $61.04 per Bbl for oil.

24

Approximately 31% of our total proved reserves as of December 31, 2005 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2005, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

Our level of indebtedness may adversely affect our operations and limit our growth. We may have difficulty making debt service payments on our indebtedness as such payments become due.

As of March 31, 2006, our total debt was $472.0 million and our total book capitalization was $508.0 million. Our maximum commitment amount and the borrowing base under our Credit Agreement are $450.0 million and $172.5 million, respectively. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

Our level of indebtedness affects our operations in several ways, including the following:

• a significant portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

• we may be at a competitive disadvantage as compared to similar companies that have less debt;

• the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

• changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving bank credit facility; and

• we may be more vulnerable to general adverse economic and industry conditions.

If an event of default occurs under our Credit Agreement or our 8 ¹/2% Senior Notes, the lenders or noteholders may declare the principal of, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit

25

Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas production, acquisition, development and exploration. We face intense competition from both major and other independent oil and natural gas companies:

• seeking to acquire desirable producing properties or new leases for future development or exploration; and

• seeking to acquire the equipment and expertise necessary to operate and develop our properties.

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

Significant capital expenditures are required to replace our reserves.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and our revolving bank credit facility. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on an economic basis to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved

26

reserves and production will decline over time. In addition, approximately 31% of our total estimated proved reserves (by volume) at December 31, 2005 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and enhanced recovery operations. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

• increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what

27

their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted.

We are subject to complex laws and regulations, including environmental and safety regulations, that can adversely affect the cost, manner and feasibility of doing business.

Our operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production and transportation of, oil and natural gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• unitization and pooling of properties;

• habitat and endangered species protection, reclamation and remediation, and other environmental protection;

• well stimulation processes;

• produced water disposal;

• safety precautions;

• operational reporting; and

• taxation.

Under these laws and regulations, we could be liable for:

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

• remediation and clean-up costs and other governmental sanctions, such as fines and penalties; and

• other environmental damages.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

28

Our use of hedging arrangements could result in financial losses or reduce our income.

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the New York Mercantile Exchange, or NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. Under our current hedging policy, we may hedge up to 80% of our anticipated monthly production for a maximum three-year period. As of March 31, 2006, we had hedged 21,390 MMcf and 2,435 MBbl of our natural gas and oil production for 2006 through 2008 at average monthly prices ranging from $6.97 to $10.15 per Mcf of natural gas and $41.64 to $67.53 per Bbl of oil. The fair value of our oil and natural gas derivative instruments outstanding as of March 31, 2006 was a liability of approximately $60.9 million. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

• our production is less than expected;

• the counter-party to the hedging contract defaults on its contract obligations; or

• there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement.

In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.

Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. Although we currently do not, and do not anticipate that we will in the future, enter into derivative contracts that require an initial deposit of cash collateral, our working capital could be impacted if we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification

29

for preclosing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted.

The loss of our Chief Executive Officer or other key personnel could adversely affect our business.

We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our CEO, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. These persons include the executive officers listed in “Management—Executive officers and directors.” Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

If Mark A. Fischer ceases to be either our Chairman, CEO or President in connection with a change of control, such event could also result in a change of control event occurring under our Phantom Unit Plan as described in “Management—Phantom unit plan.”

Oil and natural gas drilling and producing operations can be hazardous and may expose us to environmental or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

• injury or loss of life;

• severe damage to or destruction of property, natural resources and equipment;

• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigations and administrative, civil and criminal penalties; and

• injunctions or other proceedings that suspend, limit or prohibit operations.

Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease prior to the date we acquire them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities. Moreover, in the future, we may not be able to obtain such insurance coverage at premium levels that justify its purchase.

Costs of environmental liabilities could exceed our estimates.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated

30

materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

• the uncertainties in estimating clean up costs;

• the discovery of additional contamination or contamination more widespread than previously thought;

• the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

• future changes to environmental laws and regulations.

Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing at cost-effective rates. Our ability to access financial markets and obtain cost-effective rates in the future are dependent on a number of factors, many of which we cannot control, including changes in:

• our credit ratings;

• interest rates;

• the structured and commercial financial markets;

• market perceptions of us or the oil and natural gas exploration and production industry; and

• tax rates due to new tax laws.

All of the outstanding borrowings under the Credit Agreement as of March 31, 2006 are subject to market rates of interest as determined from time to time by the banks. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

The concentration of accounts for our oil and gas sales, joint interest billings or hedging with third parties could expose us to credit risk.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables, but we may incur an immaterial loss in connection with the bankruptcy of Entergy New Orleans, Inc. Future concentration of sales of oil and natural gas commensurate with decreases in commodity prices could result in adverse effects.

In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.

31

Risks related to the notes

A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.

Under U.S. bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims under the guarantee may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee, received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and:

• was insolvent or rendered insolvent by reason of such incurrence;

• 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 guarantee, you would no longer have a claim against the 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 guarantees from being voided under fraudulent transfer law.

32

Upon a change of control, we may not have the ability to raise the funds necessary to finance the change of control offer required by the indenture governing the notes, which would violate the terms of the notes.

Upon the occurrence of a change of control, holders of the notes will have the right to require us to purchase all or any part of such holders’ notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of purchase. There can be no assurance that either we or our subsidiary guarantors would have sufficient financial resources available to satisfy all of our or their obligations under these notes in the event of a change in control. Our failure to purchase the notes as required under the indenture would result in a default under the indenture which could have material adverse consequences for us and the holders of the notes. See “Description of the new notes—Change of control.”

The notes will be effectively subordinated to liabilities and indebtedness of our non-guarantor subsidiaries and subordinated to any of our secured indebtedness to the extent of the assets securing such indebtedness.

As of June 30, 2006, we had approximately $159.0 million of secured indebtedness outstanding under our Credit Agreement and $13.0 million of additional secured indebtedness. Holders of this indebtedness and any secured indebtedness that we may incur in the future will have claims with respect to our assets constituting collateral for such indebtedness that are prior to your claims under the notes. In the event of a default on such secured indebtedness or our bankruptcy, liquidation or reorganization, those assets would be available to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made on the notes. Accordingly, any such secured indebtedness will effectively be senior to the notes to the extent of the value of the collateral securing the indebtedness. While the indenture governing the notes places some limitations on our ability to create liens, there are significant exceptions to these limitations, including with respect to sale and leaseback transactions, that will allow us to secure some kinds of indebtedness without equally and ratably securing the notes. To the extent the value of the collateral is not sufficient to satisfy the secured indebtedness, the holders of that indebtedness would be entitled to share with the holders of the notes and the holders of other claims against us with respect to our other assets.

In addition, the notes may not be guaranteed by all of our subsidiaries in the future, and any non-guarantor subsidiaries can incur some indebtedness under the terms of the indenture. 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. As of the closing date, all of our existing wholly-owned subsidiaries will be guarantors of the notes.

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness or we may experience a financial failure, which may hinder the receipt of payment on the notes.

Our ability to make scheduled payments or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot

33

assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. See “Forward-looking statements” and “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources.”

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements including our Credit Agreement and the indenture governing the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Credit Agreement restricts and the indenture governing the notes will restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. See “Description of certain indebtedness” and “Description of the new notes.”

If we cannot make scheduled payments on our debt, we will be in default and, as a result:

• our debt holders could declare all outstanding principal and interest to be due and payable;

• the lenders under our Credit Agreement could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and

• we could be forced into bankruptcy or liquidation, which is likely to result in delays in the payment of the notes and in the exercise of enforcement remedies under the notes or the subsidiary guarantees.

In addition, provisions under the bankruptcy code or general principles of equity that could result in the impairment of your rights include the automatic stay, avoidance of preferential transfers by a trustee or a debtor-in-possession, limitations of collectability of unmatured interest or attorneys’ fees and forced restructuring of the notes.

Covenants in our debt agreements restrict our business in many ways.

The indenture governing the notes will contain various covenants that limit our ability and/or our restricted subsidiaries’ ability to, among other things:

• incur or assume liens or additional debt or provide guarantees in respect of obligations of other persons;

• issue redeemable stock and preferred stock;

• pay dividends or distributions or redeem or repurchase capital stock;

• prepay, redeem or repurchase debt;

• make loans, investments and capital expenditures;

• enter into agreements that restrict distributions from our subsidiaries;

34

• sell assets and capital stock of our subsidiaries;

• enter into certain transactions with affiliates;

• consolidate or merge with or into, or sell substantially all of our assets to, another person; and

• enter into new lines of business.

In addition, our Credit Agreement also contains restrictive covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those tests. A breach of any of these covenants could result in a default under our Credit Agreement and/or the notes. Upon the occurrence of an event of default under our Credit Agreement, the lenders could elect to declare all amounts outstanding under our Credit Agreement to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our Credit Agreement could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under our Credit Agreement. If the lenders under our Credit Agreement accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our Credit Agreement and our other indebtedness, including the notes. See “Description of certain indebtedness.”

Our borrowings under our Credit Agreement are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income would decrease.

35

Ratio of earnings to fixed charges

The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year Ended December 31,					Three Months Ended March 31, 2006
	2001	2002	2003	2004	2005
Ratio of earnings to fixed charges	3.6x	3.1x	5.3x	5.4x	2.3x	2.8x

The ratio was computed by dividing earnings by fixed charges. For this purpose, “earnings” represent the aggregate of pre-tax income from continuing operations before cumulative effect of accounting change plus fixed charges excluding capitalized interest. “Fixed charges” include interest expensed, capitalized interest and amortization of debt issuance costs.

36

Use of proceeds

The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the private offering of the old notes. 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 in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

37

Capitalization

The following unaudited table sets forth our capitalization as of March 31, 2006 and should be read together with our financial statements and the accompanying notes included in this prospectus.

(Dollars in thousands)	As of March 31, 2006
Cash and cash equivalents	$	8,476
Long-term debt, including capital leases and current maturities(1):
Credit Agreement(2)		134,000
Other		13,025
8 1/2% Senior Notes due 2015		325,000
Total debt		472,025
Stockholders’ equity:
Common stock, $.01 par value; 1,000 shares issued and outstanding		1
Additional paid-in capital		—
Retained earnings		68,155
Accumulated other comprehensive loss, net of taxes		(32,146	)
Total stockholders’ equity		36,010
Total capitalization	$	508,035

(1) Includes current maturities of long-term debt and capital leases of $3.4 million.

(2) As of June 30, 2006, we had $159.0 million of indebtedness outstanding under our Credit Agreement.

38

Unaudited pro forma financial data

The following unaudited pro forma condensed financial information for the fiscal year ended December 31, 2005 gives effect to the following transactions:

• our acquisition of the limited partner interest in CEI Bristol, including hedge settlement costs; and

• the issuance of $325.0 million principal amount of our 8 ¹/2% Senior Notes on December 1, 2005 and the application of net proceeds.

The following unaudited pro forma financial information and explanatory notes present how the combined financial statements of Chaparral and CEI Bristol may have appeared had the two transactions above been effective as of January 1, 2005.

The unaudited pro forma combined financial information shows the impact of the acquisition of the limited partners’ interest in CEI Bristol on Chaparral’s historical results of operations under the purchase method of accounting. The unaudited pro forma financial information combines the historical financial information of Chaparral and CEI Bristol for the year ended December 31, 2005.

The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined. In addition, as explained in more detail in the accompanying notes to the unaudited pro forma combined financial information, the allocation of the purchase price reflected in the pro forma combined financial information is subject to adjustment and may vary from the actual purchase price allocation that will be recorded.

39

Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement of

operations for the year ended December 31, 2005

(Dollars in thousands)	Chaparral historical			CEI Bristol historical			Adjustments (Note 2)			Pro forma
Revenues
Oil and gas sales	$	201,410		$	29,773		$	—		$	231,183
Loss on oil and gas hedging activities		(68,324	)		(12,836	)		—			(81,160	)
Total revenues		133,086			16,937			—			150,023
Costs and expenses
Lease operating		42,147			6,867			(693	)(a)		48,321
Production tax		14,626			2,458			—			17,084
Depreciation, depletion and amortization		31,423			4,818			1,700	(b)		37,941
General and administrative		9,808			196			693	(a)		10,697
Total costs and expenses		98,004			14,339			1,700			114,043
Operating income		35,082			2,598			(1,700	)		35,980
Non-operating income (expense)
Interest expense		(15,588	)		—			(17,517	)(c)		(33,105	)
Other income		665			20			(3	)(d)		682
Net non-operating income (expense)		(14,923	)		20			(17,520	)		(32,423	)
Income before income taxes		20,159			2,618			(19,220	)		3,557
Income tax expense		7,309			—			(6,019	)(e)		1,290
Net income	$	12,850		$	2,618		$	(13,201	)	$	2,267

40

Notes to unaudited pro forma condensed

consolidated statement of operations

Note 1: Basis of presentation

The accompanying unaudited pro forma statement of operations of Chaparral for the year ended December 31, 2005 has been prepared to give effect to the issuance of $325.0 million principal amount of the notes issued on December 1, 2005, and the acquisition of CEI Bristol as if the transactions occurred on January 1, 2005. The effects of the issuance of the $325.0 million principal amount of the notes are not included in the pro forma combined financial information included in Note 2 to the Chaparral Energy, Inc. financial statements.

Chaparral uses the full cost method of accounting for its oil and gas producing activities while CEI Bristol uses the successful efforts method of accounting. Adjustments have been made to present the pro forma condensed consolidated statements of operations on the full cost method of accounting for oil and gas operations.

All intercompany balances and transactions have been eliminated.

Note 2: Pro forma adjustments

The unaudited pro forma statement of operations includes the following adjustments:

(a) Represents the elimination of joint operating overhead reimbursements historically charged to CEI Bristol by Chaparral.

(b) Represents the adjustment of depletion, depreciation and amortization of oil and gas properties related to the allocation of additional basis of oil and gas properties associated with the purchase price allocation and change in accounting for depletion, depreciation and amortization for CEI Bristol from successful efforts to full cost.

(c) Represents the adjustment to historical interest expense for the debt issued in connection with the offering of the notes and for the reduction of the revolving credit facility as presented in the following table:

(Dollars in thousands)	Year ended December 31, 2005
Historical interest expense	$	15,588
Interest expense resulting from the notes issued		25,323
Reduction in interest expense from the reduction of the revolving credit line		(8,648	)
Amortization of $9.1 million deferred financing costs related to the notes issued—10 years		842
Total pro forma interest expense	$	33,105

(d) Elimination of CEI Bristol’s gain on sale of oil and gas properties as required by the full-cost method of accounting. Also includes the elimination of the 1% general partners interest of equity in earnings of CEI Bristol historically included in Chaparral’s income statement.

(e) Adjustments to record the income tax impact of the inclusion of CEI Bristol’s results of operations and the pro forma adjustments at Chaparral’s effective tax rate of 36.3%.

41

Selected consolidated financial data

You should read the following financial data of Chaparral in connection with the financial statements and related notes and “Management’s discussion and analysis of financial condition and results of operations” included in this prospectus. The financial data as of and for each of the five years ended December 31, 2005 were derived from our audited consolidated financial statements. The data for the three months ended March 31, 2005 and 2006 were derived from our unaudited interim consolidated financial statements appearing in this prospectus. In the opinion of management, this three-month data includes all normal recurring adjustments necessary for a fair statement of the results for those interim periods. Our historical results are not necessarily indicative of results to be expected in future periods.

	Year ended December 31,															Three months ended March 31,
(Dollars in thousands)	2001			2002			2003			2004			2005			2005 (unaudited)			2006 (unaudited)
Operating results data:
Revenues
Oil and gas sales	$	44,250		$	42,653		$	74,186		$	113,546		$	201,410		$	36,149		$	61,295
Gain (loss) on oil and gas hedging activities		10			(749	)		(12,220	)		(21,350	)		(68,324	)		(8,839	)		(1,153	)
Total revenues		44,260			41,904			61,966			92,196			133,086			27,310			60,142
Costs and expenses
Lease operating		13,566			15,037			19,520			26,928			42,147			8,636			15,133
Production taxes		3,226			3,114			4,840			8,272			14,626			2,651			4,658
Depreciation, depletion and amortization		5,835			7,910			10,376			17,533			31,423			6,251			11,053
General and administrative		3,506			4,059			4,946			5,985			9,808			2,300			3,405
Total costs and expenses		26,133			30,120			39,682			58,718			98,004			19,838			34,249
Operating income		18,127			11,784			22,284			33,478			35,082			7,472			25,893
Non-operating income (expense)
Interest expense		(4,966	)		(3,998	)		(4,116	)		(6,162	)		(15,588	)		(2,345	)		(9,165	)
Other income		201			1,012			208			279			665			173			104
Net non-operating expense		(4,765	)		(2,986	)		(3,908	)		(5,883	)		(14,923	)		(2,172	)		(9,061	)
Income from continuing operations before income taxes and accounting change		13,362			8,798			18,376			27,595			20,159			5,300			16,832
Income tax expense		5,099			3,134			6,932			9,880			7,309			2,037			6,460
Income from continuing operations before accounting change		8,263			5,664			11,444			17,715			12,850			3,263			10,372
Cumulative effect of change in accounting principle, net of income taxes		—			—			(887	)		—			—			—			—
Discontinued operations, net of income taxes		(575	)		(617	)		—			—			—			—			—
Net income	$	7,688		$	5,047		$	10,557		$	17,715		$	12,850		$	3,263		$	10,372

42

	Year ended December 31,															Three months ended March 31,
(Dollars in thousands)	2001			2002			2003			2004			2005			2005 (unaudited)		2006 (unaudited)
Cash flow data:
Net cash provided by operating activities	$	13,036		$	17,480		$	32,541		$	49,849		$	65,111		18,336		29,020
Net cash used in investing activities		(47,846	)		(27,505	)		(55,213	)		(95,120	)		(334,435	)	(34,149	)	(47,044	)
Net cash provided by financing activities		24,821			8,921			26,146			54,061			257,080		9,913		24,902

	As of December 31,														As of March 31, 2006 (unaudited)
(Dollars in thousands)	2001		2002			2003			2004			2005
Financial position data:
Cash and cash equivalents	$	2,237	$	1,578		$	5,052		$	13,842		$	1,598		$	8,476
Total assets		129,855		142,919			211,086			308,827			647,379			682,476
Total debt		79,868		91,780			118,355			176,622			446,544			472,025
Undistributed earnings		15,373		20,420			30,977			48,692			58,133			68,155
Accumulated other comprehensive income (loss), net of income taxes		3,379		(3,733	)		(4,900	)		(12,107	)		(47,967	)		(32,146	)
Total equity		18,753		16,688			26,078			36,586			10,167			36,010

43

Management’s discussion and analysis of financial

condition and results of operations

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this prospectus.

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

Overview

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, East Texas, North Texas and the Rocky Mountains. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and enhanced oil recovery projects. As of December 31, 2005, we had estimated proved reserves of 618 Bcfe, with a PV-10 value of $1.6 billion. Our reserves were 69% proved developed and 67% gas.

On September 30, 2005, we acquired the limited partner interest in CEI Bristol Acquisition, L.P. from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. Total consideration paid by us, including costs associated with the settlement of all previously existing hedge positions by CEI Bristol, was approximately $158 million. Prior to this acquisition, we held a 1% general partner interest through our wholly-owned subsidiary Chaparral Oil, L.L.C. and TIFD III-X LLC held a 99% limited partner interest in CEI Bristol. Chaparral Oil, L.L.C. also managed CEI Bristol and its properties since 2000.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and gas activities.

Oil and gas prices fluctuate widely. The prices we receive for our oil and gas production affect our:

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• quantity of oil and natural gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. See “—Quantitative and qualitative disclosures regarding market risks” below for a discussion of our hedging and hedge positions.

44

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

We believe the most significant, subjective or complex estimates we make in preparation of our financial statements are:

• the amount of estimated revenues from oil and gas sales;

• the quantity of our proved oil and gas reserves;

• the timing of future drilling, development and abandonment activities;

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

We base our estimates on historical experience and various assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates.

Comparison of three months ended March 31, 2006 to three months ended March 31, 2005

Oil and gas sales.    Oil and gas sales before losses from hedging activity for the three months ended March 31, 2006 increased $25.1 million, or 70%, from the same period in 2005. The increase was due to average realized prices being 27% higher in the first quarter of 2006 and an increase of 34% in production volumes compared to the same period in 2005. The average prices received for oil increased 26% to $59.77 per barrel and for gas increased 27% to $7.30 per Mcf in the first quarter of 2006 compared to the same period in 2005.

Our loss from oil and gas hedging activities in the first quarter of 2006 decreased by $7.7 million from the first quarter of 2005. As a result of lower NYMEX forward strip prices at March 31, 2006 compared to December 31, 2005, hedge ineffectiveness resulted in a gain of $7.4 million in the first quarter of 2006 compared to a loss of $4.3 million in the same period of 2005. Hedge settlement losses increased $4.1 million due to increased prices and production volumes. The effect of our hedging program decreased average realized prices $0.15 per Mcfe in the first quarter of 2006 compared to a decrease of $1.59 per Mcfe in the first quarter of 2005.

Production volumes increased 34% (1,880 MMcfe) in the first quarter of 2006 compared to the same period in 2005 primarily due to the addition of volumes from acquisitions, our expanded drilling program, and enhancements of our existing properties. Production volumes during the first quarter of 2006 increased compared to the same period in 2005 by 21% (823 MMcfe) in the Mid-Continent, 31% (208 MMcfe) in the Permian Basin, 87% (438 MMcfe) in East Texas, 16% (31 MMcfe) in the Gulf Coast, 179% (145 MMcfe) in North Texas, and 158% (235 MMcfe) in the Rocky Mountains.

Lease operating expenses.    Lease operating expenses during the first quarter of 2006 increased $6.5 million, or 75%, compared to the same period in 2005 due to increases in the number of net producing wells and higher oilfield service costs. We incurred $2.0 million of costs associated with workovers in the first quarter of 2006 compared to $0.8 million in the same period in 2005. On a per unit basis, lease operating expenses increased $0.48 per Mcfe primarily due to higher field level costs.

45

Production taxes.    Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased during the first quarter of 2006 by $2.0 million compared to the same period in 2005. This increase was caused by a 27% increase in prices and a 34% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.48 to $0.62 due primarily to higher prices.

Depreciation, depletion and amortization (DD&A).    DD&A increased during the first quarter of 2006 by $4.8 million, or 77%, compared to the same period in 2005 primarily due to an increase in DD&A on oil and gas properties of $4.6 million. For oil and gas properties, $2.5 million of the increase was due to higher production volumes in 2006 and $2.1 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.38 to $1.34 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expenses (G&A).    G&A expense increased during the first quarter of 2006 by $1.1 million, or 48%, compared to the same period in 2005. The increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $2.2 million in the first quarter of 2006 and $1.3 million in the first quarter of 2005 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.41 per Mcfe in the first quarter of 2005 to $0.46 per Mcfe in the first quarter of 2006.

Interest expense.    Interest expense increased during the first quarter of 2006 by $6.8 million, or 291%, compared to the same period in 2005 primarily as a result of the issuance of our 8 ¹/2% Senior Notes on December 1, 2005.

Comparison of year ended December 31, 2005 to year ended December 31, 2004

Oil and gas sales.    Oil and gas sales before losses from hedging activity in 2005 increased $87.9 million, or 77%, from 2004. The increase was due to average realized prices being 33% higher in 2005 and an increase of 34% in production volumes. The average prices received for oil increased 33% to $53.76 per barrel and for gas increased 34% to $7.41 per Mcf compared to 2004. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $47.0 million from 2004. Of the $47.0 million increase, $32.8 million was related to hedge settlement payments and $14.2 million was due to hedge ineffectiveness. The effect of our hedging program decreased average realized prices $2.69 per Mcfe in 2005 compared to a decrease of $1.13 of Mcfe in 2004.

Production volumes increased 34% (6,393 MMcfe) from 2004 primarily due to our expanded drilling program, the addition of volumes from acquisitions and enhancements of our existing properties. Production volumes increased by 19% (2,770 MMcfe) in the Mid-Continent, 26% (586 MMcfe) in the Permian Basin, 259% (1,943 MMcfe) in East Texas, 105% (376 MMcfe) in the Gulf Coast, 36% (203 MMcfe) in North Texas, and 248% (515 MMcfe) in the Rocky Mountains.

Lease operating expenses.    Lease operating expenses increased $15.2 million, or 57%, from 2004 due to increases in the number of net producing wells and higher oilfield service costs. Approximately $2.4 million was due to increases in gas handling charges primarily due to increased production volumes. We incurred $4.5 million of costs associated with workovers in 2005 compared to $2.4 million in 2004. On a per unit basis, lease operating expenses increased $0.24 per Mcfe primarily due to higher field level costs.

46

Production taxes.    Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased in 2005 by $6.4 million from 2004. This increase was caused by a 33% increase in prices and a 34% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.44 to $0.58 due primarily to higher prices.

Depreciation, depletion and amortization.    DD&A increased $13.9 million, or 79%, primarily due to an increase in DD&A on oil and gas properties of $13.1 million. For oil and gas properties, $7.0 million of the increase was due to higher production volumes in 2005 and $6.1 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.32 to $1.09 per Mcfe primarily due to estimated higher future development costs for reserve extensions and discoveries.

General and administrative expenses.    G&A expense increased by $3.8 million, or 64%, from 2004. Approximately $0.5 million of the increase is due to professional fees associated with documenting our internal controls over financial reporting for compliance with the Sarbanes- Oxley Act of 2002. The remainder of the increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $6.2 million in 2005 and $4.2 million in 2004 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.32 per Mcfe in 2004 to $0.39 per Mcfe in 2005.

Interest expense.    Interest expense increased by $9.4 million, or 153%, compared to 2004, primarily as a result of increased levels of borrowings and higher interest rates paid. Approximately $5.6 million of the increase is due to an increase of approximately $64.0 million in the average amount outstanding under the Credit Agreement and term notes and an increase in the average interest rate paid from 4.3% in 2004 to 5.7% in 2005 (which is 33.3% higher than 2004). Approximately $2.4 million of the increase is due to the issuance of the 8 ¹/2% Senior Notes on December 1, 2005 and $1.4 million of the increase is due to the GE Bridge Loan entered into to finance the CEI-Bristol acquisition.

Comparison of year ended December 31, 2004 to year ended December 31, 2003

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $39.4 million, or 53%, from 2003. The increase was due to the average realized price being 24% higher in 2004 and an increase of 24% in production volumes. The average price received for oil increased 36% to $40.53 per barrel and for gas increased 16% to $5.54 per Mcf compared to 2003. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $9.1 million from 2003. The effect of our hedging program decreased the average realized price by $1.13 per Mcfe in 2004 compared to a decrease of $0.80 per Mcfe in 2003.

Production volumes increased 24% (3,655 MMcfe) from 2003 due to our drilling program, additions from acquisitions and enhancements of our existing properties. Production volumes increased in our areas by 10% (1,452 MMcfe) in the Mid-Continent, 148% (1,349 MMcfe) in the Permian Basin, 88% (351 MMcfe) in East Texas, 63% (138 MMcfe) in the Gulf Coast, 134% (325 MMcfe) in North Texas, and 24% (40 MMcfe) in the Rocky Mountains.

Lease operating expenses.    Lease operating expenses increased $7.4 million, or 38%, from 2003 due to increases in the number of net producing wells and higher oilfield service costs. We incurred $2.4 million of costs associated with workovers in 2004 compared to $1.6 million in 2003.

47

On a per unit basis, lease operating expenses increased $0.14 per Mcfe primarily due to higher field level costs.

Production taxes.    Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales and increased by $3.4 million from 2003. This increase was caused mostly by a 24% increase in prices and a 24% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.32 to $0.44 primarily due to higher prices.

Depreciation, depletion and amortization.    DD&A of oil and gas properties increased $6.5 million, DD&A for property and equipment increased $0.5 million and the accretion for our asset retirement obligation increased $0.2 million for a total increase of $7.2 million, or 69%, from 2003. For oil and gas properties, $2.8 million of the increase was due to higher production volumes in 2004 and $3.7 million of the increase was due to an increase in the DD&A rate per equivalent unit of production in 2004. Our DD&A rate per equivalent unit of production increased by $0.24 per Mcfe to $0.77 primarily due to estimated higher future development costs for reserve extensions and discoveries. DD&A on property and equipment increased due to acquisition of additional assets.

General and administrative expenses.    G&A expense increased by $1.0 million, or 21%, from 2003. The increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense was net of $4.2 million in 2004 and $3.1 million in 2003 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense was $0.32 per Mcfe in 2003 and 2004.

Interest expense.    Interest expense increased by $2.0 million, or 50%, compared to 2003, primarily as a result of increased levels of borrowings and higher interest rates paid. An increase in outstanding debt in 2004 accounted for $1.7 million of the increase.

Income tax expense.    The effective tax rates for 2004 and 2003 were 36% and 38% respectively. The effective tax rate exceeds the federal statutory tax rate primarily due to state income taxes imposed by the various states where we have production offset partially by reductions for statutory depletion carryforwards and other items. Estimates of future taxable income can be significantly affected by changes in oil and gas prices, estimates of the timing and amount of future production and estimates of future operating expenses and capital costs.

Cumulative effect of change in accounting principle.    We adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” as of January 1, 2003. This statement changed the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. As a result of our adoption of SFAS No. 143, we recorded a $4.4 million increase in the net capitalized costs of our oil and gas properties and an initial asset retirement obligation of $5.9 million. Additionally, we recognized a cumulative loss effect of the accounting change of $0.9 million, net of a tax benefit of $0.5 million.

Liquidity and capital resources

Overview.    Our primary sources of liquidity are cash generated from our operations and our $450.0 million revolving credit line. At March 31, 2006, we had approximately $8.5 million of cash and cash equivalents and $37.5 million of availability under our revolving credit line with a borrowing base of $172.5 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to

48

meet our normal recurring operating needs, debt service obligations, planned capital expenditures and contingencies for the next 12 months.

We pledge our producing oil and gas properties to secure our revolving credit line. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. If oil and gas prices decrease from the amounts used in estimating the collateral value of our oil and gas properties, the borrowing base may be reduced, thus reducing funds available for our capital expenditures. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and gas prices through the use of commodity derivatives.

In this section we describe our current plans for capital expenditures, identify the resources available to fund the capital expenditures and discuss the principal factors that can affect our liquidity and capital resources.

Capital expenditures.    For the year ended December 31, 2005, we incurred actual costs as summarized by area in the following table:

(Dollars in thousands)	For the year ended December 31, 2005(1)		Percent of total
Mid-Continent	$	158,999	47.7%
Permian Basin		74,762	22.4%
East Texas		24,880	7.5%
North Texas		29,177	8.8%
Rocky Mountains		13,213	4.0%
Gulf Coast		32,007	9.6%
	$	333,038	100.0%

(1) Includes $4.7 million of additions relating to increases in Chaparral’s asset retirement obligations.

In addition to the capital expenditures for oil and gas properties, we spent approximately $5.7 million for acquisition and construction of new office and administrative facilities and equipment during 2005.

49

Our current 2006 capital expenditure budget for oil and gas properties is $210.0 million assuming our initial public offering of common stock is consummated. Our 2005 actual and 2006 budgeted capital expenditures are detailed in the table below:

(Dollars in thousands)	For the year ended December 31, 2005(1)		Percent of total	2006 budgeted capital expenditures		Percent of total
Development activities:
Developmental drilling	$	81,527	24.5%	$	91,000	43.3%
Enhancements		15,549	4.7%		22,000	10.5%
Tertiary recovery		6,403	1.9%		16,000	7.6%
Acquisitions		222,285	66.7%		70,000	33.4%
Exploration activities		7,274	2.2%		11,000	5.2%
Total	$	333,038	100.0%	$	210,000	100.0%

(1) Includes $4.7 million of additions relating to increases in Chaparral’s asset retirement obligations.

Our budgeted development and exploratory drilling capital expenditures summarized by area are detailed in the table below:

(Dollars in thousands)	2006 drilling capital expenditures		Percent of total
Mid-Continent	$	61,000	59.8%
Permian Basin		11,000	10.8%
East Texas		1,000	1.0%
North Texas		9,000	8.8%
Rocky Mountains		10,000	9.8%
Gulf Coast		10,000	9.8%
	$	102,000	100.0%

A majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells. We also have budgeted increased capital expenditures for our CO₂ tertiary recovery projects in the Mid-Continent and Permian Basin.

We continually evaluate our capital needs and compare them to our estimated funds available. Our actual expenditures during fiscal 2006 may be higher or lower than our budgeted amounts. The final determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources by us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and permitting for the potential drilling locations.

Cash provided from operating activities.    Substantially all of our cash flow from operating activities is from the production and sale of oil and gas reduced by associated hedging activities. We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the year ended December 31, 2005, the net cash provided from

50

operations was approximately 36% of our net cash used in investing activities excluding the CEI Bristol acquisition. For the year ended December 31, 2005, cash flow from operating activities increased by 31% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense.

For the three months ended March 31, 2006, net cash provided from operations increased 58% from the same period in the prior year and provides approximately 62% of our net cash outflows used in investing activities. The increase is due primarily to an increase in oil and gas sales revenue, partially offset by higher operating expenses.

Our current credit facility.    We entered into a Sixth Restated Credit Agreement, which we refer to as our Credit Agreement, on June 22, 2005 which provides for a $450.0 million maximum commitment amount, is secured by our oil and gas properties and matures on June 22, 2009. Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. Prior to the acquisition of CEI Bristol, the borrowing base was increased from $235.0 million to $270.0 million on September 30, 2005. At September 30, 2005 we had an outstanding balance of $243.5 million under our Credit Agreement, and the borrowing base was $270.0 million. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of our additional debt issued in the offering of our 8 ¹/2% Senior Notes on December 1, 2005. As of June 30, 2006, we had $159.0 million outstanding under our Credit Agreement and the borrowing base was $200.0 million.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At March 31, 2006 all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. At March 31, 2006, the LIBOR rate was 4.83%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.18% resulting in an effective interest rate of 7.01% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus 1/2 of 1%; plus a margin where the margin varies from 0.00% to 0.50% depending on the utilization percentage of the borrowing base. At March 31, 2006 the applicable rate was 7.75% and the applicable margin was 0.25% resulting in an effective interest rate of 8.00% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

51

Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our Credit Agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. The agreement also requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 and a Minimum Debt Service Coverage Ratio, as defined in our Credit Agreement, of not less than 1.0. We believe we are in compliance with all covenants as of March 31, 2006.

The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in accordance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be useful as a measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2005 and March 31, 2006 our current ratio as computed using generally accepted accounting principles was 0.65 and 0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.05 and 1.57, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

	December 31,			March 31,
(Dollars in thousands)	2005			2006
Current assets per GAAP	$	77,255		$	75,797
Plus—Availability under Credit Agreement		62,500			37,500
Less—Deferred tax asset on hedges and asset retirement obligation		(24,057	)		(14,616	)
Less—Short-term hedge instruments		(1,016	)		(3,818	)
Current assets as adjusted	$	114,682		$	94,863
Current liabilities per GAAP	$	119,292		$	102,244
Less—Short term hedge instruments		(63,125	)		(41,452	)
Less—Short term asset retirement obligation		(346	)		(364	)
Current liabilities as adjusted	$	55,821		$	60,428
Current ratio for loan compliance		2.05			1.57

On September 30, 2005, in connection with the CEI Bristol acquisition, we borrowed $132.0 million from General Electric Capital Corporation. This loan, which we referred to as the GE Bridge Loan, was due at maturity on June 30, 2006, bore interest at LIBOR plus 2% and was collateralized by the oil and gas properties of CEI Bristol. The net proceeds of the offering of our 8 ¹/2% Senior Notes on December 1, 2005 were used to repay approximately $175.0 million of the amount outstanding under the Credit Agreement and pay off the GE Bridge Loan.

Our 8 ¹/2% Senior Notes due 2015.    On December 1, 2005, we sold $325.0 million aggregate principal amount of 8 ¹/2% Senior Notes maturing on December 1, 2015. There is no sinking fund

52

for the 8 ¹/2% Senior Notes. The 8 ¹/2% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 ¹/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries.

On and after December 1, 2010, we may redeem some or all of the 8 ¹/2% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

In addition, upon completion of a qualified equity offering prior to December 1, 2008, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 ¹/2% Senior Notes from the proceeds, so long as:

• we pay to the holders of such notes a redemption price of 108.5% of the principal amount of the 8 ¹/2% Senior Notes, plus accrued and unpaid interest to the date of redemption; and

• at least 65% of the aggregate principal amount of the 8 ¹/2% Senior Notes remains outstanding after each such redemption, other than 8 ¹/2% Senior Notes held by us or our affiliates.

Finally, prior to December 1, 2010, the notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indenture.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8 ¹/2% Senior Notes. The provisions of the indenture limit our and our restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

• make investments;

• incur liens;

• create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;

• engage in transactions with our affiliates;

• sell assets, including capital stock of our subsidiaries; and

• consolidate, merge or transfer assets.

If we experience a change of control (as defined in the indenture governing the 8 ¹/2% Senior Notes), subject to certain conditions, we must give holders of the 8 ¹/2% Senior Notes the opportunity to sell to us their 8 ¹/2% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Alternative capital resources.    We have historically used cash flow from operations and secured bank financing as our primary sources of capital. In the future we may use additional sources such as asset sales, public or private issuances of common or preferred stock, or project financing.

53

While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

Contractual obligations.    The following table summarizes our contractual obligations and commitments as of December 31, 2005:

(Dollars in thousands)(1)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:
Revolving credit line—including estimated interest expense	$	7,050	$	126,597	$	—	$	—	$	133,647
Senior notes, including estimated interest expense		27,625		82,875		82,875		407,875		601,250
Other long-term notes—including estimated interest expense		3,598		5,200		5,030		233		14,061
Capital leases—including estimated interest		153		214		—		—		367
Abandonment obligations		346		6,305		520		8,625		15,796
Derivative obligations		62,109		32,001		—		—		94,110
Total	$	100,881	$	253,192	$	88,425	$	416,733	$	859,231

(1) As of December 31, 2005, the Company has no off-balance sheet arrangements.

Critical accounting policies and estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See Note 1 to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

Revenue recognition.    We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.

Hedging.    Our crude oil and natural gas derivative contracts are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity”, as amended, or SFAS 133. This policy significantly impacts the timing of revenue or expense recognized from this activity as our contracts are adjusted to their fair value at the end of each month. Pursuant to SFAS 133, the effective portion of the hedge gain or loss, meaning that the change in the fair value of the contract offsets the

54

changes in the expected future cash flows from our forecasted production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) on oil and gas hedging activities” line in our consolidated statements of income. Until hedged production is reported in earnings and the contract settles, the change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in our consolidated statements of member’s equity/stockholders’ equity (deficit). The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) on oil and gas hedging activities” line item each period. If our hedges did not qualify for cash flow hedge treatment, then our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

Oil and gas properties.

• Full cost accounting.    We use the full cost method of accounting for our oil and gas properties. Under this method, all costs incurred in the exploration and development of oil and gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.

• Proved oil and gas reserves quantities.    Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.

Our proved reserve information included in this prospectus is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 84% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2005 and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

• Depreciation, depletion and amortization.    The quantities of proved oil and gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

• Full cost ceiling limitation.    Under the full cost method, the net capitalized costs of oil and gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10% plus the lower of cost or fair market value of unevaluated properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues are those in effect as of the last day of the quarter. If oil and gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and gas properties could occur in the future.

55

• Costs not subject to amortization.    Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. At December 31, 2005 we had approximately $10.2 million of costs excluded from the amortization base. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

• Future development and abandonment costs.    Our future development cost include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgements are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

The accounting for future abandonment costs changed on January 1, 2003 with our adoption of Statement on Financial Accounting Standards No. 143. This standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. The present value calculation requires us to make numerous assumptions and judgments, including the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

Income taxes.    We provide for income taxes in accordance with Statement on Financial Accounting Standards No. 109, “Accounting for Income Taxes”. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Valuation allowance for NOL carryforwards.    In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards

56

expire 15 to 20 years from the year of origination. Generally we assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We will record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.

Recent accounting pronouncements

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29”, or SFAS 153. SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. We adopted this statement in the third quarter of 2005, and it did not have a material effect on our financial statements.

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments”, or SFAS 123R. SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. We adopted SFAS No. 123R as of January 1, 2006 and for stock awards on and after that date, the Black-Scholes option pricing model will be used to value those stock awards. The adoption of SFAS No. 123R did not have a material effect on our financial statements.

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. We expect to apply the guidance of FIN 47 commencing January 1, 2006 and expect no impact on our financial statements.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 requires voluntary changes in accounting principles to be applied retrospectively, unless it is impracticable. SFAS No. 154’s retrospective application requirement replaces APB 20’s requirement to recognize most voluntary changes in accounting principle by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. If retrospective application for all prior periods is impracticable, the method used to report the change and the reason the retrospective application is impracticable are to be disclosed.

Under SFAS No. 154, retrospective application will be the transition method in the unusual instance that a newly issued accounting pronouncement does not provide specific transition guidance. It is expected that many pronouncements will specify transition methods other than retrospective. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005, and the adoption of this statement is expected to have no impact on our financial position or results of operations.

The FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair

57

value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on our financial position, results of operations or cash flows.

Effects of inflation and pricing

While the general level of inflation affects certain of our costs, factors unique to the oil and gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and gas, price fluctuations have had, and will continue to have, a material effect on us.

Quantitative and qualitative disclosures regarding market risks

Oil and gas prices.    Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our year ended December 31, 2005 production, our gross revenues from oil and gas sales would change approximately $1.7 million for each $0.10 change in gas prices and $1.4 million for each $1.00 change in oil prices.

58

We periodically enter into derivative contracts, consisting primarily of swaps, to manage our exposure to decreases in oil and gas prices. When using swaps to hedge our oil and gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133 which allows the aggregate change in fair value to be recorded as accumulated other comprehensive income (loss) on the consolidated balance sheet. Recognition in the income statement occurs in the period of contract settlement. Our Credit Agreement allows us to hedge up to 80% of our expected future production for three years. Our outstanding hedges as of March 31, 2006 are summarized below:

	Natural gas				Crude oil
Period	Total MMcf	Weighted average fixed price to be received		Percent of PDP production hedged	Total MBbl	Weighted average fixed price to be received		Percent of PDP production hedged
04/2006 to 06/2006	3,420	$	7.06	69.4%	312	$	41.80	73.1%
07/2006 to 09/2006	3,330		7.06	71.6%	306		44.26	74.7%
10/2006 to 12/2006	2,910		8.04	65.8%	294		47.10	74.8%
01/2007 to 03/2007	2,610		8.61	61.8%	270		49.24	71.7%
04/2007 to 06/2007	2,610		7.04	64.5%	267		49.40	73.1%
07/2007 to 09/2007	2,610		7.05	68.7%	258		54.11	77.2%
10/2007 to 12/2007	1,410		8.67	38.5%	210		59.48	65.1%
01/2008 to 03/2008	960		10.07	27.3%	168		65.06	54.6%
04/2008 to 06/2008	870		8.10	25.6%	168		64.66	56.0%
07/2008 to 09/2008	510		8.21	15.5%	133		64.54	45.4%
10/2008 to 12/2008	150		8.92	4.7%	49		66.45	17.2%

Interest rates.    All of the outstanding borrowings under our Credit Agreement as of March 31, 2006 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

59

Business and properties

Our business

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to developmental drilling. As of December 31, 2005, approximately 84% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties. On September 30, 2005, we acquired the 99% limited partner interest in CEI Bristol for $158 million. We have managed this limited partnership since 2000.

As of December 31, 2005, we had estimated proved reserves of 618 Bcfe and a PV-10 value of $1.6 billion. For the year ended December 31, 2005, on a pro forma basis, our average daily production was 81 MMcfe. For the three months ended March 31, 2006, our average daily production was 83 MMcfe, a 34% increase over the same period in 2005. As of December 31, 2005 our estimated pro forma reserve life is 20.9 years. For the year ended December 31, 2005, on a pro forma basis, our revenues were $150.0 million. For the three months ended March 31, 2006, our revenues were $60.1 million. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value, beginning on page 19.

For the period from 2002 to 2005, our proved reserves and production have grown at a compounded annual growth rate of 35% and 26%, respectively. We have grown primarily through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

We have a multi-year inventory of drillable prospects and an active drilling program. We have identified over 790 proved developmental drilling locations, as well as over 2,100 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our 2005 drilling rate. We normally have three to six drilling rigs active at any time, depending on the availability of rigs. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and are currently permitting on one additional proprietary 3-D shoot.

Our capital expenditures for oil and gas properties for the year ended December 31, 2005 were $333.0 million, representing a 247% increase over the prior year. Excluding $152.9 million recorded for the oil and gas properties acquired as part of the CEI Bristol acquisition, our capital expenditures in 2005 for oil and gas properties were $180.1 million, representing an 88% increase over the prior year. Our capital expenditure budget for oil and gas properties for 2006 is $210.0 million. We have budgeted approximately 62% of our 2006 capital expenditures on development activities (drilling—43%, enhancements—11% and tertiary recovery—8%), 33% for

60

acquisitions and 5% for exploration activities. The majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO₂) tertiary recovery projects in the Mid-Continent and Permian Basin.

Chaparral Energy, Inc. was incorporated in the state of Delaware on September 14, 2005 as a wholly owned subsidiary of Chaparral, L.L.C. Chaparral, L.L.C. was then merged with and into Chaparral Energy, Inc. effective September 16, 2005, with Chaparral Energy, Inc. surviving the merger. At the effective time of the merger, all shares of capital stock of Chaparral Energy, Inc. issued and outstanding prior to the merger were cancelled and all units of Chaparral, L.L.C. issued and outstanding prior to the merger were converted to shares of the surviving entity, Chaparral Energy, Inc.

Business strengths

Consistent track record of low-cost reserve additions and production growth.    From 2002 to 2005, we have grown reserves and production by a compounded annual growth rate of 35% and 26%, respectively. We have achieved this through a combination of drilling success and acquisitions. Our reserve replacement ratio, which reflects our reserve additions in a given period stated as a percentage of our production in the same period, has averaged nearly 500% per year since 1999. We replaced approximately 468%, 794% and 822% of our production in 2003, 2004 and 2005 respectively, at an average fully developed FD&A cost of $1.82 per Mcfe over this three-year period, which we believe is among the lowest in the industry.

Disciplined approach to acquisitions.    We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence, with reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2003, 2004 and 2005 our capital expenditures for acquisitions were $19.9 million, $30.5 million and $222.3 million, respectively. These acquisition capital expenditures represented approximately 35%, 32% and 67%, respectively, of our total capital expenditures for those years. In 2005 we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added an estimated 115 Bcfe of proved reserves, as of September 30, 2005. Excluding the acquisition of CEI Bristol, we spent $69.3 million on acquisitions during 2005, representing approximately 39% of our total capital expenditures for that period. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

Property enhancement expertise.    Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation of coiled tubing or siphon string, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.

61

Inventory of drilling locations.    As of December 31, 2005, we had an inventory of over 790 proved developmental drilling locations and over 2,100 additional potential drilling locations, which combined represent over 15 years of drilling inventory based on our 2005 drilling rate as shown in the following table.

	Identified proved undeveloped drilling locations	Identified other potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net
Mid-Continent	653	1,440	295,482	33,524
Permian Basin	81	470	49,915	11,718
East Texas	4	34	30,219	1,352
North Texas	30	146	16,349	2,924
Rocky Mountains	14	25	10,025	7,286
Gulf Coast	11	12	25,399	6,775
Total	793	2,127	427,389	63,579

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 22. We spent $87.3 million on development and exploration drilling for 2005. We have experienced a high historical drilling success rate of approximately 96% on a weighted average basis during 2003, 2004 and 2005. For 2006, we have budgeted $102.0 million to drill more than 80 operated wells and to participate in more than 130 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO₂ enhanced oil recovery. CO₂ enhanced oil recovery involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO₂ tertiary recovery operations, as well as specific software for modeling CO₂ enhanced recovery. We own a 29.2% interest in and operate a large CO₂ tertiary flood unit in southern Oklahoma and installed and operate a second tertiary flood unit with a 54% interest in the Oklahoma panhandle. At December 31, 2005, our proved reserves included 4 properties where CO₂ tertiary recovery methods are used, which comprise approximately 9% of our total proved reserves.

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 34 years after starting his career at Exxon as petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 22 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Joe Evans, our Chief Financial Officer, has over 27 years of experience in the oil and gas industry. Individuals in our 24-person management team have an average of over 25 years of experience in the oil and gas industry.

62

Business strategy

We seek to grow reserves and production profitably through a balanced mix of developmental drilling, acquisitions, enhancements, tertiary oil recovery projects and a modest number of exploration projects. Further, we strive to control our operations and costs and to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:

Continue lower-risk development drilling program.    We have allocated $91.0 million, or 43% of our current 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. We generally pursue mature properties in the second half of their life which are located in proven fields in which we have an opportunity to improve operations through cost control, and to increase production and reserves through the application of improved technology and additional drilling. Excluding the CEI Bristol acquisition, which was larger than our typical acquisitions, we spent approximately $69.3 million on acquisitions during 2005. Our 2006 acquisition capital budget is currently $70 million, or 33% of our total capital expenditure budget.

Apply technical expertise to enhance mature properties.    Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 13 field offices throughout Oklahoma, Texas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor. As of December 31, 2005, we had an inventory of 227 developed enhancement projects requiring total estimated capital expenditures of $16.3 million.

Expand CO₂ enhanced oil recovery activities.    We have accumulated interests in 43 properties in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in certain of these properties. We plan to expand our Camrick CO₂ project in 2006 and initiate CO₂ injection in our NW Camrick and Perryton Units in 2007. We have budgeted $16 million in 2006 towards these projects. To support our existing CO₂ tertiary recovery projects, we currently inject approximately 37 MMcf per day of CO₂. We have a 100% ownership interest in our 86 mile Borger CO₂ pipeline, a 29% interest in the 120 mile Enid to Purdy CO₂ pipeline, and a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline.

Pursue modest exploration program.    In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $11.0 million, or approximately 5% of our 2006 capital expenditures, on exploration activities.

63

Control operations and costs.    We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancement, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and gas production to maximize both volumes and wellhead price. As of December 31, 2005, we operated properties comprising approximately 79% of our proved reserves.

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of March 31, 2006, we had hedges in place for approximately 69%, 59% and 19% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 74%, 72% and 44% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities of $12.2 million, $21.4 million, and $68.3 million for the years ended December 31, 2003, 2004, and 2005, respectively, as commodity prices have increased.

Properties

The following table presents proved reserves and PV-10 value as of December 31, 2005, and average daily production for the year ended December 31, 2005 and the three months ended March 31, 2006 by major areas of operation.

	Proved reserves as of December 31, 2005						Average daily production (MMcfe per day)	Pro forma average daily production (MMcfe per day)	Average daily production (MMcfe per day)
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	Percent of total MMcfe	PV-10 value ($mm)		Year ended December 31, 2005	Year ended December 31, 2005	Three month ended March 31, 2006
Mid-Continent	20,752	285,994	410,506	66.5%	$	1,070.0	48.2	55.4	53.2
Permian Basin	6,057	73,347	109,689	17.8%		265.3	7.8	9.3	9.9
East Texas	1,257	26,059	33,601	5.4%		90.5	7.4	8.3	10.4
North Texas	2,239	3,977	17,411	2.8%		48.5	2.1	2.5	2.5
Rocky Mountains	1,916	4,245	15,741	2.5%		37.4	2.0	2.5	2.5
Gulf Coast	1,692	20,762	30,914	5.0%		90.9	2.0	3.0	4.3
Total	33,913	414,384	617,862	100.0%	$	1,602.6	69.5	81.0	82.8

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and gas properties is geographically diversified, 81% of our 2005 production was concentrated in our core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2005 we owned interests in 5,455 gross (1,422 net) producing wells and we operated wells representing 79% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

64

Mid-Continent

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2005, accounted for 66% of our proved reserves and 67% of our PV-10 value. We own an interest in 3,636 wells in the Mid-Continent, of which we operate 944. Our three largest properties and 13 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2005, our net average daily production in the Mid-Continent Area was approximately 48.2 MMcfe per day, or 69% of our total net average daily production (or approximately 55.4 MMcfe per day, or 68% of our total net average daily production, on a pro forma basis). During the three months ended March 31, 2006, our net average daily production in the Mid-Continent Area was approximately 53.2 MMcfe per day, or 64.2% of our total net average daily production. This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

Camrick area—Beaver and Texas Counties, Oklahoma.    The Camrick area represents 6% of our proved reserves and 6.2% of the PV-10 value of our proved reserves at December 31, 2005. This area consists of three unitized fields, the Camrick Unit, which covers 9,080 acres, the NW Camrick Unit, which covers 4,080 acres and the Perryton Unit, which covers 2,040 acres. We currently operate these three fields with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs at a depth of approximately 6,800 feet. The three units have produced approximately 16.1 MMBbl of primary reserves and approximately 13.4 MMBbl of secondary reserves. There are approximately 36 active producing wells in this area. Currently CO₂ injection operations are under way in the Phase I area of the Camrick Unit. CO₂ injection has improved the gross production in the Camrick Unit from approximately 110 Bbls per day in 2001 from 11 wells to approximately 800 Bbls per day for the first quarter of 2006 from 17 wells. We currently plan to expand CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma.    SWAGSU represents 4.9% of our proved reserves and 5.8% of the PV-10 value of our proved reserves at December 31, 2005. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1966, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have approximately 22 active producing wells in this unit. Since January 2005, we have re-entered three wells, drilled one well and are scheduled to drill four additional wells in 2006.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas.    We own approximately 6,120 acres in the Cleveland Sand Play. The Cleveland Sand occurs at 8,300 feet and is considered a tight gas sand reservoir. We currently have interests in 18 Cleveland Sand producing wells, have drilled three wells in 2005 and have plans to drill five wells in 2006. Horizontal drilling technology has been employed in two recently drilled wells. Future wells will utilize a mix of vertical and horizontal technology.

65

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma.    The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO₂ injection program was initiated in 1982. This miscible CO₂ injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996 miscible CO₂ injection began in the downdip section of the Sims C2. We have approximately 47 active producing wells in this unit.

Harmon County 3-D Shoot—Harmon County, Oklahoma.    We have leased in excess of 29,000 acres in Harmon County, Oklahoma and have conducted a proprietary 3-D seismic shoot on this acreage. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling of three wells is expected to start in the third quarter of 2006 with the potential to drill 150 wells.

CO₂ Enhanced Recovery Operations—Various counties, Oklahoma and Texas.    We plan to expand our Camrick CO₂ project in 2006 and initiate CO₂ injection in our NW Camrick and Perryton Units in 2007. We have in place transportation and supply agreements to provide the necessary CO₂ for these projects. With this expansion, we expect to increase our CO₂ volumes transported to 30 MMcf per day by July 2006.

We have accumulated 43 properties in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations. We have a 100% ownership and operate our 86 mile Borger CO₂ pipeline, own a 29% interest in the 120 mile Enid to Purdy CO₂ pipeline, and own a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline. To facilitate the expansion of our CO₂ tertiary recovery program currently budgeted in the next three years, we will be extending our CO₂ pipeline infrastructure by 88 miles. Arrangements to secure additional sources of CO₂ are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in April 2005 estimating that significant oil reserves could be technically recovered in the State of Oklahoma through CO₂ enhanced oil recovery processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2005, accounted for 18% of our proved reserves and 17% of our PV-10 value. We own an interest in 916 wells in the Permian Basin, of which we operate 285. Six of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2005, our net average daily production in the Permian Basin Area was approximately 7.8 MMcfe per day, or 11% of our total net average daily production (or approximately 9.3 MMcfe per day, or 11% of our total net average daily production, on a pro forma basis). During the three months ended March 31, 2006, our net average daily production in the Permian Basin Area was approximately 9.9 MMcfe per day, or 12% of our total net average daily production. Similar to the Mid-Continent Area, it is characterized by its stable long life shallow decline reserves.

Tunstill Field Play—Loving and Reeves Counties, Texas.    Our original Tunstill Field Play covers approximately 6,480 acres. We operate these wells with a working interest of 100%. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 feet. Older wells produce from

66

the shallower Bell Canyon Sands including the Ramsey and Olds while more recent wells have established production from the deeper Cherry Canyon Sands as well as the shallower sands. During the year ended December 31, 2005, we drilled nine wells in this play. We have identified 36 potential drilling locations in this play, of which eight are scheduled to be drilled in 2006. We have acquired leasehold rights to approximately 12,880 acres that are an expansion to our original Tunstill field play.

Haley Area Strawn and Morrow Play—Loving County, Texas.    The Haley Area Strawn and Morrow Play encompasses 3,840 gross acres. We own interests in and operate five producing wells in this play. Production has been established from two main intervals: the Strawn at a depth of approximately 15,500 feet and the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Strawn and the other three wells are completed in the Morrow. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. We are currently completing two recently drilled wells.

East Texas

East Texas is one of our four growth areas and, as of December 31, 2005, accounted for 5% of our proved reserves and 5% of our PV-10 value. We own an interest in 116 wells in East Texas, of which we operate 98. These reserves are characterized by shorter life and higher initial potential.

Giddings North Edwards—Fayette County, Texas.    We control 4,780 acres in the Gidding North Edwards Field. We operate this field with an average working interest of 98%. Eight wells are producing from the Edwards Lime that occurs at a depth of 10,100 feet. These eight wells have produced 554 MBbls of oil and 42.3 Bcf of natural gas. We have recently drilled and are awaiting completion on an Edwards test and are currently drilling a second Edwards test in this field. We have recently leased an additional 1,200 acres adjacent to this field.

Winnsboro Field—Wood County, Texas.    We control approximately 1,072 acres in the Winnsboro Field and operate 11 wells. Primary objectives in this field are the Travis Peak and Cotton Valley that occur at depths from 8,600 to 10,300 feet. Additional potential pay zones are the Sub-Clarksville, Bacon Lime, Hill, Gloyd and the Pettit-Pittsburg that occur at depths from 4,150 to 8,500 feet. During 2005 we drilled one development well in this field. We have plans to drill several more development wells in this play.

North Texas

North Texas is the second of our four growth areas and, as of December 31, 2005, accounted for 3% of our proved reserves and 3% of our PV-10 value. We own an interest in 559 wells in North Texas, of which we operate 103. One of our three proprietary 3-D seismic shoots has been completed in this area.

Percy Jones Clearfork Play—Howard and Mitchell Counties, Texas.    We own and operate the Percy Jones, Percy Jones A and Percy Jones B leases, encompassing 640 acres in the Laton East Howard Field. We currently operate these properties with an average working interest of 100%. A total of 54 wells have been completed in the Glorieta at depths of 2,500 feet and Upper Clearfork at depths of 2,700 feet since its discovery in 1947. The Percy Jones lease (north half of Section 13) has a total of 44 producing wells and is developed on 10 acre spacing with some increased density development to 5 acres and cumulative production of 1.8 MMBbls of oil and

67

24 MMcf of natural gas. The Percy Jones A and B leases make up the south half of the section, have a total of 10 existing wells and have cumulative production of 365 MBbls of oil and 22 MMcf of natural gas. Secondary recovery through water injection has proven successful in offset leases but has been done on a very limited basis in the Percy Jones lease.

Recent increased density drilling activity in the Laton East Howard Field, as well as patterned waterflood development has shown marked success. This type of development in the Percy Jones leases has the potential to increase reserves since much of the south half of the section, which has only 10 existing wells, has not been developed. In addition, new productive zones have been identified by drilling through the Middle and Lower Clearfork which were not developed in existing wells in the section. Reserves from these zones will be captured in the new wells we drill and potentially through the recompletion of the existing wells to greater depths.

Since January 2005, we have drilled five wells in the north half of the section and two wells in the south half. Four wells are scheduled to be drilled in 2006. In addition, we have identified 24 PUD locations and 43 potential locations.

Eanes Units—Montague County, Texas.    We own and operate the North Eanes, East Eanes and South Eanes Units. These units cover approximately 7,000 acres and produce from the Caddo at approximately 5,600 feet. We currently operate these units with an average working interest of 95%. We have conducted an 11.5 square mile proprietary 3-D seismic program in these units. Potential pay zones have been identified in the Caddo at 5,600 feet, Atoka at 5,700 feet, Barnett shale at 6,000 feet, Mississippian Reef at 6,300 feet, Viola at 6,500 feet and the Ellenberger at 6,800 feet. We have approximately 24 active producing wells in this area. We drilled six wells in 2005. We have three wells scheduled to be drilled in 2006. We may drill up to 33 additional wells if this initial drilling effort proves successful.

Rocky Mountains

The Rocky Mountains is our third growth area and, as of December 31, 2005, accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 74 wells in the Rocky Mountains Area, of which we operate 34. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

Bakken Horizontal Play—Richland County, Montana.    We are currently pursuing acreage in Richland County, Montana. We recently drilled a dual leg horizontal well in the Bakken interval on acreage we own that was producing from the Red River formation. The McVay #2-34H well was drilled as a horizontal dual leg lateral with the first lateral measuring 3,648 feet in length and the second lateral measuring 3,496 feet in length. During March 2006, the well was producing 268 Bbls of oil per day and 159 Mcf of natural gas per day.

We recently leased approximately 10,400 acres in the immediate area of the McVay #2-34H and have participated in three additional wells in the first quarter of 2006 and have three additional wells scheduled to be drilled in 2006.

Gulf Coast

Our fourth growth area is the Gulf Coast and, as of December 31, 2005, accounted for 5% of our proved reserves and 6% of our PV-10 value. We own an interest in 154 wells in the Gulf Coast, of which we operate 73. Unlike our core areas, the Gulf Coast Area is characterized by shorter life

68

and high initial potential production. We believe a balance of this type of production with our long-life reserves adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Nueces County, TX.    We control approximately 6,000 producing acres and recently were the successful bidder on approximately 6,400 net acres of new leases to be issued by the State of Texas. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate 12 active producing wells in this area. We are currently permitting a 3D seismic survey to be conducted in 2006 over parts of this area in an attempt to find bypassed reserves or other potential reservoirs.

Vivian Borchers Area—Lavaca County, Texas.    We control approximately 1,300 acres in the Vivian Borchers Area. Multiple Frio and Miocene pay zones occur at depths shallower than 4,000 feet. Based on 3-D seismic reprocessing, we have successfully drilled and completed three wells to depths of approximately 4,000 feet. These wells had initial test rates as high as 900 Mcf of natural gas per day. In addition, we have several deep 3-D seismic based Wilcox tests planned for the area. We have licensed 200 square miles of seismic data and are currently evaluating it for additional prospects, similar to those mentioned above. As prospects are identified, additional leasing and drilling activity will be proposed.

Oil and natural gas reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2005. Information in the table is derived from reserve reports of estimated proved reserves on the top 75% of our non-CO₂ enhanced oil recovery proved undeveloped reserves prepared by Cawley, Gillespie & Associates, Inc. (80% of PV-10 value) and by Lee Keeling & Associates, Inc. for our CO₂ enhanced oil recovery proved undeveloped reserves (4% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (16% of PV-10 value).

	Net proved reserves
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	PV-10 value (In thousands)
Developed—producing	21,081	239,932	366,418	$	991,215
Developed—non-producing	2,681	43,241	59,327		157,728
Undeveloped	10,151	131,211	192,117		453,667
Total proved	33,913	414,384	617,862	$	1,602,610

The reserve life as of December 31 2003, 2004 and 2005 was 19.9, 22.9 and 24.4 years, respectively. The reserve life was calculated by dividing total proved reserves by production volumes for the year indicated.

69

The following table sets forth the estimated future net revenues from proved reserves, the PV-10, the standardized measure of discounted future net cash flows and the prices used in projecting them over the past three years.

(Dollars in thousands, except prices)	2003		2004		2005
Future net revenue	$	1,053,624	$	1,663,141	$	3,597,300
PV-10 value		488,305		775,116		1,602,610
Standardized measure of discounted future net cash flows		325,250		514,041		1,067,888
Oil price (per Bbl)	$	32.52	$	43.51	$	61.04
Natural gas price (per Mcf)	$	6.19	$	6.35	$	10.08

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

The following table sets forth information at December 31, 2005 relating to the producing wells in which we owned a working interest as of that date. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells is the total number of producing wells in which we have an interest, and net wells is the sum of our working interest in all wells.

	Total wells
	Gross	Net
Crude oil	2,529	734
Natural gas	2,926	688
Total	5,455	1,422

The following table details our gross and net interest in producing wells in which we have an interest and the number of wells we operated at December 31, 2005.

	Total wells		Operated Wells
	Gross	Net
Mid-Continent	3,636	866	944
Permian Basin	916	269	285
East Texas	116	89	98
North Texas	559	108	103
Rocky Mountains	74	25	34
Gulf Coast	154	65	73
Total	5,455	1,422	1,537

70

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2005.

	Developed		Undeveloped
	Gross	Net	Gross	Net
Mid-Continent	808,677	295,482	45,693	33,524
Permian Basin	92,664	49,915	12,088	11,718
East Texas	41,639	30,219	1,874	1,352
North Texas	21,826	16,349	3,170	2,924
Rocky Mountains	34,565	10,025	14,194	7,286
Gulf Coast	55,273	25,399	10,352	6,775
Total	1,054,644	427,389	87,371	63,579

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. Development wells are wells drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find and produce oil or gas in an unproved area, to find a new reservoir in field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.

	2003		2004		2005
	Gross	Net	Gross	Net	Gross	Net
Development wells
Productive	87.0	23.9	89.0	24.4	171.0	52.0
Dry	2.0	0.7	5.0	2.8	2.0	0.8
Exploratory wells
Productive	2.0	1.4	1.0	0.1	11.0	6.0
Dry	—	—	—	—	1.0	0.4
Total wells
Productive	89.0	25.3	90.0	24.5	182.0	58.0
Dry	2.0	0.7	5.0	2.8	3.0	1.2
Total	91.0	26.0	95.0	27.3	185.0	59.2
Percent productive	98%	97%	95%	90%	98%	98%

71

The following table sets forth certain information regarding our historical net production volumes, revenues, average prices realized and production costs associated with sales of oil and natural gas for the periods indicated.

	Year ended December 31,						Three months ended March 31,
	2003		2004		2005		2005		2006
Production:
Oil (MBbl)		924		1,173		1,449		321		431
Natural Gas (MMcf)		9,762		11,923		16,660		3,648		4,868
Combined (MMcfe)		15,306		18,961		25,354		5,574		7,454
Average daily production:
Oil (Bbls)		2,532		3,214		3,970		3,563		4,795
Natural gas (Mcf)		26,745		32,666		45,644		40,556		54,051
Combined (Mcfe)		41,937		51,950		69,464		61,934		82,821
Average prices (before effect of hedges):
Oil (per Bbl)	$	29.92	$	40.53	$	53.76	$	47.41	$	59.77
Natural Gas (Mcf)		4.77		5.54		7.41	$	5.74		7.30
Combined (per Mcfe)		4.85		5.99		7.94		6.49		8.22
Average costs per Mcfe:
Lease operating	$	1.28	$	1.42	$	1.66	$	1.55	$	2.03
Production tax	$	0.32	$	0.44	$	0.58	$	0.48	$	0.62
Depreciation, depletion, and amortization	$	0.53	$	0.77	$	1.09	$	0.96	$	1.34
General and administrative	$	0.32	$	0.32	$	0.39	$	0.41	$	0.46

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. We are unable to predict when, or if, such shortages may again occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

72

Markets

The marketing of oil and natural gas produced by us will be affected by a number of factors that are beyond our control and whose exact effect cannot be accurately predicted. These factors include:

• the amount of crude oil and natural gas imports;

• the availability, proximity and cost of adequate pipeline and other transportation facilities;

• the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind power;

• the effect of federal and state regulation of production, refining, transportation and sales;

• the laws of foreign jurisdictions and the laws and regulations affecting foreign markets;

• other matters affecting the availability of a ready market, such as fluctuating supply and demand; and

• general economic conditions in the United States and around the world.

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before, FERC, as well as nondiscriminatory access requirements, could further increase the availability of gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of gas sales from our wells.

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas from time to time with the intent of reducing the current global oversupply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells.

In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability.

Environmental matters and regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To reduce our exposure to potential environmental risk, we typically have our field personnel inspect operated properties prior to completing each acquisition.

73

General

Our operations, like the operations of other companies in our industry, 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. These laws and regulations may:

• require the acquisition of various permits before drilling commences;

• require the installation of expensive pollution control equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

• require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

• impose substantial liabilities for pollution resulting from our operation; and

• with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may affect our properties or operations. For the year ended December 31, 2005, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this prospectus, we are not aware of any environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the oil and gas exploration and production industry include the following:

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

74

All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency, or EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our presently classified wastes to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

75

Water discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe we are in substantial compliance with the requirements of the Clean Water Act.

Air emissions

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe that we are in substantial compliance with the requirements of the Clean Air Act.

Other laws and regulation

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Other regulation of the oil and gas industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

76

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. It is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and production

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural gas sales transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission, or FERC, has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines.

77

However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point-of-sale locations.

Natural gas gathering regulations

State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

State regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Seasonality

While our limited operations located in the Gulf Coast and the Rocky Mountains may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.

Legal proceedings

In the opinion of management, there are no material pending legal proceedings to which we or any of our subsidiaries are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business.

78

Title to properties

We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and gas leases or farm-in agreements. Prior to the commencement of drilling operations on undeveloped leasehold, we conduct a title examination and perform curative work with respect to any significant title defects. Prior to completing an acquisition of an interest in significant producing oil and gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in natural gas and oil properties are subject to customary royalty interests, liens for current taxes and other similar burdens and minor easements, restrictions and encumbrances which we believe do not materially detract from the value of these interests either individually or in the aggregate and will not materially interfere with the operation of our business. We will take such steps as we deem necessary to assure that our title to our properties is satisfactory. We are free, however, to exercise our judgment as to reasonable business risks in waiving title requirements.

Employees

As of March 31, 2006, we had 345 full-time employees, including 11 geologists and geophysicists, 26 production and reservoir engineers and 11 land professionals. Of these, 208 work in our Oklahoma City office and 137 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

79

Management

The following provides brief biographical information for each of our executive officers, directors and other key management personnel.

Executive officers and directors

The following table provides information regarding our executive officers and directors. We currently expect that the director nominees named below will join our board only upon the consummation of the initial public offering of our common stock. If such offering does not occur, these director nominees may not join our board of directors. In such event, our current directors, Mark A. Fischer and Charles A. Fischer, would remain our only two directors unless and until other directors were appointed or elected, or their death, removal or resignation.

Name	Age	Position
Mark A. Fischer	56	Chairman, Chief Executive Officer and President
Charles A. Fischer, Jr.	57	Chief Administrative Officer, Executive Vice President and Director
Joseph O. Evans	52	Chief Financial Officer and Executive Vice President and Director Nominee
Robert W. Kelly II	48	Senior Vice President and General Counsel
Larry E. Gateley	56	Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	43	Senior Vice President—Operations and Production Engineering
William O. Powell III	59	Director Nominee
James A. Watt	56	Director Nominee
Bill M. Lamkin	60	Director Nominee

Mark A. Fischer, Chairman, Chief Executive Officer, President and Co-Founder, co-founded Chaparral in 1988 and has served as its President and Chairman of the Board since its inception. Mr. Fischer began his career with Exxon Company USA in 1972 in the Permian Basin of West Texas where he held various positions as production engineer, reservoir engineer, field superintendent and finally supervising production engineer. From 1977 until 1980, Mr. Fischer served as the drilling and production manager for the West Texas and then Mid-Continent Division of TXO Production Corp. Prior to founding Chaparral, he served as division operations manager for Slawson Exploration Company, focusing on the Mid-Continent and Panhandle Divisions. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Fischer served as a director of the API from 1984-1986. Mr. Fischer graduated from Texas A&M University in 1972 with an honors degree in aerospace engineering. Mark A. Fischer and Charles A. Fischer, Jr. are brothers.

Charles A. Fischer, Jr., Chief Administrative Officer, Executive Vice President, Director and Co-Founder, co-founded Chaparral in 1988, and has served as its Chief Administrative Officer and Executive Vice President since July 2005. Mr. Fischer joined Chaparral full-time in 2000 and served as its Chief Financial Officer and Senior Vice President for five years until assuming the role of

80

Chief Administrative Officer. In 1978 Mr. Fischer founded C.A. Fischer Lumber Co. Ltd., which owns eight retail building supply outlets in western Canada, and is the current President. Mr. Fischer also serves as manager of Altoma Energy GP. Mr. Fischer began his career with Renewable Resources in 1974 as a senior scientist on the Polar Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south-central Canada. Mr. Fischer served as a director of the Canadian Western Retail Lumberman’s Association for 11 years, was President for 6 years, and received the 2001 Industry Achievement Award. He graduated from Texas A&M University in 1970 (Bachelor of Science degree in Biology) and the University of Wisconsin in 1973 (Master of Science degree in Ecology).

Joseph O. Evans, Chief Financial Officer & Executive Vice President & Director Nominee, joined Chaparral in July of 2005 as Chief Financial Officer. From 1998 to June 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous Commission filings for clients. Mr. Evans has instructed numerous continuing professional education courses focused on compliance with the Sarbanes Oxley Act. He is a Certified Public Accountant and an Accredited Petroleum Accountant. Mr. Evans is a graduate of the University of Central Oklahoma with a Bachelor of Science degree in Accounting.

Robert W. Kelly II, Sr. Vice President & General Counsel, joined Chaparral in 2001 and oversees the legal, land, marketing and environmental functions. Prior to joining Chaparral, Mr. Kelly worked for Ricks Exploration Inc. as Director of Business Development & Gas Marketing for two years. From 1990 until 1999, he was with EOG Resources Inc. (formerly Enron Oil & Gas Company) initially as Land Manager for its Oklahoma City division and later building their business development department. During 1989 and 1990, Mr. Kelly was a title attorney in his own partnership firm in Oklahoma City. He began his oil and gas career as a Landman with TXO Production Corp. in 1981, subsequently receiving promotions to District Landman by 1988. He is a member of the Oklahoma Bar Association, the Oklahoma Independent Producers Association, and several other business and legal associations. Mr. Kelly received a Bachelor of Business Administration (Petroleum Land Management) degree from the University of Oklahoma in 1981, and a Juris Doctor from the Oklahoma City University School of Law in 1989.

Larry E. Gateley, Sr. Vice President—Reservoir Engineering and Acquisitions, joined Chaparral in 1997 as the Reservoir Engineering and Acquisitions Manager, and currently performs reservoir studies on over 4,000 wells per year. Mr. Gateley has 32 years of diversified management and operational and technical engineering experience. His previous positions include Reservoir/Production/Drilling Engineer for Exxon Company USA, Sr. Petroleum Engineer for J.M. Huber Corp., Chief Drilling Engineer for Post Petroleum Inc., Vice President and Co-Owner of Wood-Gate Engineering Inc., Vice President of Acquisitions for SMR Energy Income Funds, and Acquisitions Manager for Frontier Natural Gas Corporation. Mr. Gateley is a registered Professional Engineer in the states of Oklahoma and Texas. He is a graduate of the University of Oklahoma with a Bachelor of Science degree in Mechanical Engineering.

James M. Miller, Sr. Vice President—Operations & Production Engineering, joined Chaparral in 1996, as Operations Engineer. Since joining Chaparral, Mr. Miller has been promoted to positions of increasing responsibility and currently oversees all company production operations and field services. Mr. Miller has gained particular expertise in the area of operating secondary and tertiary

81

recovery units. Prior to joining Chaparral, Mr. Miller worked for KEPCO Operating Inc. for one year as a petroleum engineer. From 1987 to 1995, he was employed by Robert A. Mason Production Co., as a petroleum engineer, and later as Vice President of Production. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Miller attended the University of Oklahoma and received a Bachelor of Science degree in Petroleum Engineering in 1986.

William O. Powell III, Director Nominee, has served as Senior Vice President, Chief Financial Officer and Treasurer of ABS Group of Companies since March 2005. From October 2003 to March 2004, Mr. Powell served as Vice President and Chief Accounting Officer of La Quinta Corporation. Mr. Powell retired from PricewaterhouseCoopers LLP in June 2002, where he had been employed since 1974, serving as Worldwide Engagement Leader-Partner from 1985 to 2002 for multiple clients in the energy industry. From April 2004 to February 2005 and from July 2002 to September 2003, Mr. Powell managed personal interests. Mr. Powell was a Commissioned Officer in the United States Navy from 1968 to 1974. Mr. Powell received a Bachelor of Science in Engineering from the U.S. Naval Academy and a Bachelor of Arts in Accounting from the University of West Florida. Mr. Powell is a Certified Public Accountant.

James A. Watt, Director Nominee, has served as Chief Executive Officer of Remington Oil & Gas Corporation since 1998 and has been a member of its board of directors since 1997, serving as Chairman since 2003. From 1993 to 1997, Mr. Watt served as Vice President of Exploration for Seagull E&P, Inc. From 1991 to 1993, he served as Vice President of Exploration and Exploitation for Nerco Oil & Gas, Inc. Mr. Watt served in various technical and management positions with Union Texas Petroleum Corp. from 1974 to 1991 and was a geologist with Amoco Production Company from 1971 to 1974. Mr. Watt received a Bachelor of Science in Physics from Rensselaer Polytechnic Institute in 1971.

Bill M. Lamkin, Director Nominee, served as Executive Vice President and Chief Financial Officer of Quicksilver Resources Inc. from 1999 until his retirement in November 2005. From 1978 to 1999, Mr. Lamkin was employed by Union Pacific Resources Group Inc., serving in various positions including Treasurer, Director of Financial Services and Controller. From 1976 to 1978, he served as Chief Financial Officer and Controller of Sargent Industries, Inc. Mr. Lamkin served in various management positions with Whittaker Corporation from 1966 to 1976. Mr. Lamkin received a Bachelor of Science in Physics from the University of Texas at Austin in 1967 and a B.B.A. in Accounting from Texas Wesleyan University in 1968. He is a Certified Cash Manager and a Certified Management Accountant.

Board structure and compensation of directors

Our board of directors currently consists of two members—Mark A. Fischer and Charles A. Fischer, Jr. Upon completion of our current proposed initial public offering of common stock, if consummated, our board of directors will consist of six members. Our board has determined that Messrs. Powell, Watt and Lamkin are independent under the applicable rules of the NYSE. Following the phase-in period permitted under those rules, we intend to rely initially upon the controlled company exemption from rules that would otherwise require that a majority of the members of our board be independent directors.

Upon completion of our current proposed initial public offering of common stock, if consummated, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2007,

82

2008 and 2009, respectively. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Directors who are also full-time officers or employees of our company will receive no additional compensation for serving as directors. We will provide that all other directors will receive an annual retainer of $25,000 and an annual grant of shares of restricted stock. Each non-employee director also will receive a fee of $1,500 for each board meeting attended and $1,000 for each committee meeting attended. In addition, the chairman of the audit committee will receive an annual fee of $10,000, the chairman of the compensation committee will receive an annual fee of $5,000 and the chairman of the nominating and governance committee will receive an annual fee of $5,000.

Board committees

Following the completion of our current proposed initial public offering of common stock, if consummated, our board of directors will have an audit committee, a nominating and governance committee and a compensation committee. We intend that all the members of our audit committee will be independent under applicable provisions of the Securities Exchange Act of 1934 and the NYSE rules following a phase-in period. Following the phase-in period permitted under the NYSE rules, we intend to rely initially on the controlled company exemption from rules that would otherwise require that all the members of our nominating and governance committee and of our compensation committee will be independent under applicable provisions of those rules.

Audit Committee.    The audit committee, which will consist of Messrs. Powell (chair), Watt and Lamkin upon the completion of our current proposed initial public offering of common stock, if consummated, will assist the board in overseeing (a) the integrity of our financial statements, (b) our compliance with legal and regulatory requirements, (c) the independence, qualifications and performance of our independent registered public accounting firm and (d) the performance of our internal audit function. Our board has determined that Mr. Powell will be designated an “audit committee financial expert.”

Nominating and Governance Committee.    The nominating and governance committee, which will consist of Messrs. Lamkin (chair), Watt and Evans upon the completion of our current proposed initial public offering of common stock, if consummated, will assist the board in identifying and recommending candidates to fill vacancies on the board of directors and for election by the stockholders, recommending committee assignments for directors to the board of directors, monitoring and assessing the performance of the board of directors and individual non-employee directors, reviewing compensation received by directors for service on the board of directors and its committees and developing and recommending to the board of directors appropriate corporate governance policies, practices and procedures for our company.

Compensation Committee.    The compensation committee, which will consist of Messrs. Watt (chair), Lamkin and Charles A. Fischer, Jr. upon the completion of our current proposed initial public offering of common stock, if consummated, will (a) review and approve the compensation of our executive officers and other key employees, (b) evaluate the performance of our chief executive officer and oversee the performance evaluation of senior management and

83

(c) administer and make recommendations to the board of directors with respect to our incentive-compensation plans, equity-based plans and other compensation benefit plans.

Web access

We will provide access through our website at www.chaparralenergy.com to current information relating to governance, including a copy of each board committee charter, our Code of Conduct, our corporate governance guidelines and other matters impacting our governance principles. You may also contact our General Counsel for paper copies of these documents free of charge.

Compensation committee interlocks and insider participation

None of our executive officers have served as members of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors.

Compensation of executive officers

The following table summarizes all compensation earned by our Chief Executive Officer and our four other most highly compensated executive officers during the year ended December 31, 2005, to whom we refer in this prospectus as our named executive officers. The following table does not include Joseph O. Evans, our Chief Financial Officer who joined us in July 2005.

Summary compensation table

		Annual Compensation
	Year	Salary		Bonus		All Other Compensation(1)(2)
Mark A. Fischer	2005	$	303,000	$	19,629	$	15,307
Chairman, Chief Executive Officer and President
Charles A. Fischer, Jr.	2005	$	187,980	$	13,482	$	13,470
Chief Administrative Officer, Executive Vice President and Director
Larry E. Gateley	2005	$	164,559	$	12,176	$	8,826
Senior Vice President—Reservoir Engineering and Acquisitions
Robert W. Kelly II	2005	$	154,304	$	11,273	$	8,279
Senior Vice President and General Counsel
James M. Miller	2005	$	144,615	$	10,684	$	83,996
Senior Vice President—Operations and Production Engineering

(1) Includes: for Mark A. Fischer, $5,623 reflecting allocable expenses for personal use of aircraft and vehicles and $9,684 in Chaparral matching 401(k) contributions; for Charles A. Fischer, Jr., $3,397 reflecting allocable expenses for personal use of aircraft and vehicles and $10,073 in Chaparral matching 401(k) contributions; for Larry E. Gateley, $8,826 in Chaparral matching 401(k) contributions; for Robert W. Kelly II, $8,279 in Chaparral matching 401(k) contributions; and for James M. Miller, $76,231 in payments pursuant to overriding royalty interests subject to vesting and $7,765 in Chaparral matching 401(k) contributions.

(2) Does not include payments to Mark A. Fischer and Charles A. Fischer, Jr. made pursuant to previously granted overriding royalty interests which are vested and owned by Mark A. Fischer and Charles A. Fischer, Jr. See “Certain relationships and related transactions—Participation interests.”

84

Phantom unit plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, or the Plan, to provide deferred compensation to certain key employees as the participants. Phantom units may be awarded to participants in total up to 2% of the fair market value of Chaparral, as defined by the Plan. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with us due to death, disability, retirement or termination by Chaparral without cause. Also, phantom units vest if a change of control event occurs. A change of control event will occur under the Plan if (1) our three current stockholders collectively sell a majority of their shares (either publicly or privately) to a person who is not majority owned by them collectively, and in the process lose operational control of us (i.e., the position of President, Chief Executive Officer or Chairman of us or our subsidiary Chaparral Energy, LLC, is not held by either Mark A. Fischer or Chuck A. Fischer), (2) the termination, liquidation or dissolution of us or Chaparral Energy, LLC unless our business is substantially carried on by a successor company that remains majority owned or operationally controlled as described above, or (3) we sell all or substantially all of our assets. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Compensation expense is recognized over the vesting periods of the phantom units. We recognized deferred compensation expense of $120,000 and $525,000 for the year ended December 31, 2004 and 2005, respectively, and $110,000 for the three months ended March 31, 2006 related to the Plan.

Employment agreements

We have agreed to pay Joseph O. Evans an annual salary of $212,000 and an aggregate bonus of not less than $50,000 for his first year of employment with us, which began July 1, 2005. In addition, on July 1, 2005, we granted Mr. Evans a $50,000 award under our Phantom Unit Plan. We have also agreed to pay Mr. Evans a minimum severance amount of $424,000 in bonus and phantom units if we terminate his employment without cause, if a change of control occurs, if Chaparral is terminated, liquidated or dissolved or if we sell substantially all of the assets of Chaparral, at any time before June 30, 2010. Our severance arrangement with Mr. Evans will terminate automatically after the completion of our initial public offering of common stock on the adoption of a revised severance package by the compensation committee.

We have granted certain participation interests in the form of overriding royalty interests to James M. Miller. Our subsidiary, Chaparral CO₂, L.L.C., has assigned Mr. Miller an overriding royalty interest equal to a total 0.00500 net revenue interest in the production from the Northwest Camrick Unit, the Camrick Unit and the North Perryton (George Morrow) Unit, in each case limited to the unitized Upper Morrow Sand formation. The assignments provide that if Mr. Miller terminates his employment between the following dates, the applicable portions of the overriding royalty interests granted will automatically revert to Chaparral CO₂, L.L.C.: July 1, 2000 and June 30, 2002, 100%; July 1, 2002 and June 30, 2004, 80%; July 1, 2004 and June 30, 2005, 60%; July 1, 2005 and June 30, 2006, 40%; July 1, 2006 and June 30, 2007, 20%. Mr. Miller may terminate his employment with us at any time on or after July 1, 2007, without any part of the overriding royalty interest granted reverting to us. In the event of Mr. Miller’s death, if we terminate Mr. Miller’s employment for any reason or if Chaparral Energy, L.L.C. merges into another entity in which Chaparral is not the surviving entity or if there is a sale of Chaparral Energy, L.L.C. before July 1, 2007, the entire overriding royalty interest granted will be owned by

85

Mr. Miller without the possibility of reversion. In addition, if we sell our interest in one of the Units covered by the assignment, the overriding royalty interest granted with respect to that Unit will be owned by Mr. Miller without possibility of reversion.

Indemnification agreements

We have also entered into indemnification agreements with all of our directors and some of our executive officers. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of the State of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

• us, except for:

• claims regarding the indemnitee’s rights under the indemnification agreement;

• claims to enforce a right to indemnification under any statute or law; and

• counter-claims against us in a proceeding brought by us against the indemnitee; or

• any other person, except for claims approved by our board of directors.

We have also agreed to obtain and maintain director and officer liability insurance for the benefit of each of the above indemnities. These policies will include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnities will be named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.

86

Principal stockholders

The following table sets forth information, as of June 2, 2006, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, each director nominee and each of the five most highly compensated executive officers, by all directors, director nominees and executive officers as a group. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act and does not give effect to a stock split that would be effected as a stock dividend if we complete the initial public offering of our common stock prior to completion of the exchange offer contemplated by this prospectus.

	Beneficial ownership
Name(1)	Number	Percent
Mark A. Fischer(2)	500	50%
Altoma Energy G.P.(3)	500	50%
Charles A. Fischer, Jr.(4)	500	50%
Joseph O. Evans	—	—
Robert W. Kelly II	—	—
Larry E. Gateley	—	—
James M. Miller	—	—
William O. Powell III(5)	—	—
James A. Watt(5)	—	—
Bill M. Lamkin(5)	—	—
All Directors, Director Nominees and Officers as a group (9 persons)	1,000	100%

 * Less than 1%.

(1) The address of the directors and executive officers and principal stockholders is in care of Chaparral Energy, Inc., 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.

(2) Includes 250 shares owned of record by the Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 250 shares owned of record by Susan L. Fischer 1994 Trust, for which Susan L. Fischer, the spouse of Mark A. Fischer, serves as trustee.

(3) Charles A. Fischer, Jr., our director, Chief Administrative Officer and Executive Vice President, is one of four managing general partners and beneficially owns a 23.15% general partner interest (including 0.90% owned by his spouse) in Altoma Energy G.P. The other partners of Altoma Energy G.P. who are each managing general partners and beneficially own in excess of 5% of its general partner interests are: Kenneth H. McCourt—36.75%; Ronald D. Jakimchuck—17.86%; and Gary H. Klassen—12.80%.

(4) Includes all 500 shares owned of record by Altoma Energy G.P. Charles A. Fischer, Jr. serves as one of four managing partners of Altoma Energy G.P. Charles A. Fischer, Jr. owns directly a 22.25% general partner interest and his spouse owns directly a 0.90% general partner interest in Altoma Energy G.P.

(5) We expect that each non-employee director nominee will be granted shares of restricted stock upon the closing of our initial public offering of common stock, which shares shall vest in equal one-third increments upon each of the first three anniversary dates of the initial grant date.

87

Certain relationships and related transactions

CEI Bristol

Prior to September 30, 2005, Chaparral managed and administered the business of CEI Bristol Acquisition, L.P. At December 31, 2004, we had accounts receivable of approximately $1,444,000, due from CEI Bristol. Chaparral acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were approximately $939,000 and $1,018,000 for the years ended December 31, 2003 and 2004, respectively and $735,000 for the nine months ended September 30, 2005. Additionally, we were compensated for management services provided to CEI Bristol through a management fee. Management fees earned by Chaparral were approximately $89,000 and $228,000 for the years ended December 31, 2003 and 2004, respectively and $111,000 for the nine months ended September 30, 2005. On September 30, 2005 we acquired the 99% limited partner interest in CEI Bristol Acquisition L.P. and therefore will no longer receive any of these fees.

Participation interests

Historically, Chaparral has granted participation interests in the form of overriding royalty interests to a limited number of employees. Chaparral has also granted pro rata certain overriding royalty interests to its stockholders or their affiliates, including Mark A. Fischer and Charles A. Fischer, Jr. We believe that the granting of these participation interests to our employees in certain prospects promotes in them a proprietary interest in our exploration efforts for the benefit of us and our stockholders. Aggregate payments on these interests to all persons were $314,251, $522,965 and $612,075 in 2003, 2004 and 2005, respectively. Payments on these interests to Mark A. Fischer were $82,999, $130,509 and $120,373 in 2003, 2004 and 2005, respectively. Payments on these interests to Charles A. Fischer, Jr. were $21,572, $34,421 and $31,758 in 2003, 2004 and 2005, respectively. We made grants of additional overriding royalty interests in 2005.

We do not intend to continue the grant of any additional participation interest to our stockholders, or their affiliates, including Mark A. Fischer or Charles A. Fischer, Jr. We have discontinued the granting of overriding royalty interests under our existing program to other employees effective December 31, 2005, other than certain specified wells that spud prior to April 1, 2006.

Port Aransas property

On December 28, 2005, Mark A. Fischer acquired our beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112,475 in cash together with the assumption of a loan, which represents our net book value and its estimated current fair market value. The house was acquired by us in April 2004 for the purchase price of $327,500. Record title was taken in the name of Mark A. Fischer, and Mr. Fischer entered into a mortgage securing a $262,000 loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral enjoyed the use of the house, our board of directors approved the payment by our subsidiary of the downpayment on the house and the principal and interest payments on the loan. We made monthly payments of principal and interest totaling approximately $37,697 through November 2005.

88

Registration rights agreement

In connection with our initial public offering of common stock, we intend to enter into a registration rights agreement with each of our three existing stockholders. Under the agreement, any one of the three existing stockholders may require us to file a registration statement under the Securities Act to register the sale of shares of our common stock, subject to certain limitations, including that the reasonably anticipated gross proceeds must be at least $15.0 million. These stockholders may request a total of six such registrations (two by the Mark A. Fischer 1994 Trust, two by the Susan L. Fischer 1994 Trust, and two by Altoma Energy G.P.) and only one in any six-month period. These stockholders also have the right to cause us to register their registrable securities on Form S-3, when it becomes available to us, if the reasonably anticipated gross proceeds would be at least $10.0 million. In addition, if we propose to register securities under the Securities Act, then the stockholders who are party to the agreement will have “piggy-back” rights, subject to quantity limitations determined by underwriters if the offering involves an underwriting, to request that we register their registrable securities. There is no limit to the number of these “piggy-back” registrations in which these stockholders may request their shares be included. We generally will bear the registration expenses incurred in connection with registrations. We will agree to indemnify these stockholders against certain liabilities, including liabilities under the Securities Act, in connection with any registration effected under the agreement. These registration rights will terminate at the earlier of (a) ten years from the closing date of our initial public offering of common stock or (b) with respect to any stockholder, the date that all registrable securities held by that stockholder may be sold in a three-month period without registration under Rule 144 of the Securities Act and such registrable securities represent less than one-percent of all outstanding shares of our capital stock.

89

Description of certain indebtedness

Credit Agreement

We entered into a Sixth Restated Credit Agreement, which we refer to as our Credit Agreement, on June 22, 2005 which provides for a $450.0 million maximum commitment amount, is secured by our oil and gas properties and matures on June 22, 2009. Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. Prior to the acquisition of CEI Bristol, the borrowing base was increased from $235.0 million to $270.0 million on September 30, 2005. At September 30, 2005 we had an outstanding balance of $243.5 million under our Credit Agreement, and the borrowing base was $270.0 million. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of our additional debt issued in the offering of our 8 ¹/2% Senior Notes on December 1, 2005. As of June 30, 2006, we had $159.0 million outstanding under our Credit Agreement and a borrowing base of $200.0 million.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At March 31, 2006 all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. At March 31, 2006, the LIBOR rate was 4.83%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.18% resulting in an effective interest rate of 7.01% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus 1/2 of 1%; plus a margin where the margin varies from 0.00% to 0.50% depending on the utilization percentage of the borrowing base. At March 31, 2006 the applicable rate was 7.75% and the applicable margin was 0.25% resulting in an effective interest rate of 8.00% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

90

Our Credit Agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. The agreement also requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 and a Minimum Debt Service Coverage Ratio, as defined in our Credit Agreement, of not less than 1.0. We believe we are in compliance with all covenants as of March 31, 2006.

The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in accordance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be useful as a measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2005 and March 31, 2006 our current ratio as computed using generally accepted accounting principles was 0.65 and 0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.05 and 1.57, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

	December 31,			March 31,
(Dollars in thousands)	2005			2006
Current assets per GAAP	$	77,255		$	75,797
Plus—Availability under Credit Agreement		62,500			37,500
Less—Deferred tax asset on hedges and asset retirement obligation		(24,057	)		(14,616	)
Less—Short-term hedge instruments		(1,016	)		(3,818	)
Current assets as adjusted	$	114,682		$	94,863
Current liabilities per GAAP	$	119,292		$	102,244
Less—Short term hedge instruments		(63,125	)		(41,452	)
Less—Short term asset retirement obligation		(346	)		(364	)
Current liabilities as adjusted	$	55,821		$	60,428
Current ratio for loan compliance		2.05			1.57

On September 30, 2005, in connection with the CEI Bristol acquisition, we borrowed $132.0 million from General Electric Capital Corporation. This loan, which we referred to as the GE Bridge Loan, was due at maturity on June 30, 2006, bore interest at LIBOR plus 2% and was collateralized by the oil and gas properties of CEI Bristol. The net proceeds of the offering of our 8 ¹/2% Senior Notes on December 1, 2005 were used to repay approximately $175.0 million of the amount outstanding under the Credit Agreement and pay off the GE Bridge Loan.

91

The exchange offer

Purpose and effect of the exchange offer

On December 1, 2005, we sold $325.0 million in aggregate principal amount at maturity of the old notes in a private placement. The old notes were sold to the initial purchasers who in turn resold the notes to a limited number of qualified institutional buyers pursuant to Rule 144A of the Securities Act.

In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes, pursuant to which we agreed to file and to use our commercially reasonable efforts to cause to be declared effective by the SEC a registration statement with respect to the exchange of the old notes for the new notes. We are making the exchange offer to fulfill our contractual obligations under that agreement. A copy of the registration rights agreement has been filed as an exhibit to the registration statement of which this prospectus is a part.

Pursuant to the exchange offer, we will issue the new notes in exchange for old notes. The terms of the new notes are identical in all material respects to those of the old notes, except that the new notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any liquidated damages related to the obligation to register. Please read “Description of the new notes” for more information on the terms of the respective notes and the differences between them.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the old notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by The Depository Trust Company, referred to as DTC, who desires to deliver such old notes by book–entry transfer at DTC.

We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

In order to participate in the exchange offer, you must represent to us, among other things, that:

• you are acquiring the new notes in the exchange offer in the ordinary course of your business;

• you are not engaged in, and do not intend to engage in, a distribution of the new notes;

• you do not have and to your knowledge, no one receiving new notes from you has, any arrangement or understanding with any person to participate in the distribution of the new notes;

92

• you are not a broker-dealer tendering old notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the new notes; and

• you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”

Terms of exchange

Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange old notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $325.0 million aggregate principal amount of 8 ¹/2% Senior Notes due 2015 are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of old notes known to us. Old notes tendered in the exchange offer must be in denominations of principal amount of $2,000 and any integral multiple of $2,000.

Our acceptance of the tender of old notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

The form and terms of the new notes being issued in the exchange offer are the same as the form and terms of the old notes except that:

• the new notes being issued in the exchange offer will have been registered under the Securities Act;

• the new notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

• the new notes being issued in the exchange offer will not contain the registration rights contained in the old notes.

Expiration, extension and amendment

The expiration time of the exchange offer is 5:00 P.M., New York City time, on August 18, 2006. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any old notes by giving oral or written notice of an extension to the holders of old notes as described below. During any extension period, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions described below under “—Conditions to the exchange offer.” We may decide to waive any of the

93

conditions in our discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non–acceptance or termination to the holders of the old notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the old notes, file a post–effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 A.M., New York City time, on the first business day after the previously scheduled expiration time.

Procedures for tendering

Valid tender

Except as described below, a tendering holder must, prior to the expiration time, transmit to Wells Fargo Bank, National Association, the exchange agent, at the address listed below under the caption “—Exchange agent”:

• a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

• if old notes are tendered in accordance with the book–entry procedures listed below, an agent’s message transmitted through DTC’s Automated Tender Offer Program, referred to as ATOP.

In addition, you must:

• deliver certificates, if any, for the old notes to the exchange agent at or before the expiration time; or

• deliver a timely confirmation of the book–entry transfer of the old notes into the exchange agent’s account at DTC, the book–entry transfer facility, along with the letter of transmittal or an agent’s message; or

• comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by DTC to, and received by, the exchange agent and forming a part of a book–entry confirmation, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

If the letter of transmittal is signed by a person other than the registered holder of old notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The old notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the old notes must be signed exactly as the name of any registered holder appears on the old notes.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys–in–fact, officers of corporations or others acting

94

in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the new notes are being acquired in the ordinary course of business of the person receiving the new notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the new notes. Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”

The method of delivery of old notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through DTC’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of DTC on such dates.

No old notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all old notes, agent’s messages, letters of transmittal and other documents must be made to the exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC’s ATOP system may make book–entry delivery of the old notes by causing DTC to transfer the old notes into the exchange agent’s account. The tender by a holder of old notes, including pursuant to the delivery of an agent’s message through DTC’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered old notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not validly tendered or any old notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of old notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of old notes, nor shall any of them incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such irregularities have been cured or waived. Any old notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

95

Although we have no present plan to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any old notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any old notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

Signature guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the old notes surrendered for exchange are tendered:

• by a registered holder of the old notes who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

• for the account of an “eligible institution.”

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning of Rule 17Ad-15 under the Exchange Act.

Book-entry transfer

The exchange agent will make a request to establish an account for the old notes at DTC for purposes of the exchange offer. Any financial institution that is a participant in DTC’s system may make book–entry delivery of old notes by causing DTC to transfer those old notes into the exchange agent’s account at DTC in accordance with DTC’s procedure for transfer. The participant should transmit its acceptance to DTC at or prior to the expiration time or comply with the guaranteed delivery procedures described below. DTC will verify this acceptance, execute a book–entry transfer of the tendered old notes into the exchange agent’s account at DTC and then send to the exchange agent confirmation of this book–entry transfer. The confirmation of this book–entry transfer will include an agent’s message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

Delivery of new notes issued in the exchange offer may be effected through book–entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:

• be transmitted to and received by the exchange agent at the address listed under “—Exchange agent” at or prior to the expiration time; or

• comply with the guaranteed delivery procedures described below.

Delivery of documents to DTC in accordance with DTC’s procedures does not constitute delivery to the exchange agent.

96

Guaranteed delivery

If a registered holder of old notes desires to tender the old notes, and the old notes are not immediately available, or time will not permit the holder’s old notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book–entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:

• the tender is made through an eligible institution;

• prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

1. stating the name and address of the holder of old notes and the amount of old notes tendered,

2. stating that the tender is being made, and

3. guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered old notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the certificates for all physically tendered old notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

Determination of validity

We will determine in our sole discretion all questions as to the validity, form and eligibility of old notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular old note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular old note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular old note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within a reasonable period of time.

Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of old notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

97

Acceptance of old notes for exchange; issuance of new notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all old notes properly tendered. We will issue the new notes promptly after acceptance of the old notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

For each old note accepted for exchange, the holder will receive a new note registered under the Securities Act having a principal amount equal to that of the surrendered old note. As a result, registered holders of old notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the old notes. Old notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Under the registration rights agreement, we may be required to make additional payments in the form of liquidated damages to the holders of the old notes under circumstances relating to the timing of the exchange offer.

In all cases, issuance of new notes for old notes will be made only after timely receipt by the exchange agent of:

• certificate for the old notes, or a timely book-entry confirmation of the old notes, into the exchange agent’s account at the book-entry transfer facility;

• a properly completed and duly executed letter of transmittal or an agent’s message; and

• all other required documents.

Unaccepted or non-exchanged old notes will be returned without expense to the tendering holder of the old notes. In the case of old notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged old notes will be credited to an account maintained with DTC as promptly as practicable after the expiration or termination of the exchange offer. For each old note accepted for exchange, the holder of the old note will receive a new note having a principal amount equal to that of the surrendered old note.

Interest payments on the new notes

The new notes will bear interest from the most recent date to which interest has been paid on the old notes for which they were exchanged. Accordingly, registered holders of new notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Old notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the old notes.

98

Withdrawal rights

Tender of old notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For a withdrawal to be effective with respect to old notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “—Exchange agent” or, in the case of eligible institutions, at the facsimile number, or a properly transmitted “Request Message” through DTC’s ATOP system. Any notice of withdrawal must:

• specify the name of the person, referred to as the depositor, having tendered the old notes to be withdrawn;

• identify the old notes to be withdrawn, including certificate numbers and principal amount of the old notes;

• contain a statement that the holder is withdrawing its election to have the old notes exchanged;

• other than a notice transmitted through DTC’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the old notes register the transfer of the old notes in the name of the person withdrawing the tender; and

• specify the name in which the old notes are registered, if different from that of the depositor.

If certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If old notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn old notes.

Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange. New notes will not be issued in exchange unless the old notes so withdrawn are validly re-tendered.

Properly withdrawn old notes may be re-tendered by following the procedures described under “—Procedures for tendering” above at any time at or before the expiration time.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

99

Conditions to the exchange offer

Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any old notes for any new notes, and, as described below, may terminate an exchange offer, whether or not any old notes have been accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:

• there shall occur a change in the current interpretation by the staff of the SEC which permits the new notes issued pursuant to such exchange offer in exchange for old notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such new notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

• any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

• a banking moratorium shall have been declared by United States federal or New York State authorities;

• trading on the New York Stock Exchange or generally in the United States over-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

• an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

• a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole discretion, deem necessary for the consummation of such exchange offer; or

• any change, or any development involving a prospective change, in our business or financial affairs or any of our subsidiaries has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the old notes or the new notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offer and/or with such acceptance for exchange or with such exchange.

If we determine in our sole discretion that any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “—Expiration, extension and amendment” above.

100

If any of the above events occur, we may:

• terminate the exchange offer and promptly return all tendered old notes to tendering holders;

• complete and/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered old notes until the extended exchange offer expires;

• amend the terms of the exchange offer; or

• waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the old notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

Resales of new notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the new notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the new notes are acquired in the ordinary course of the holder’s business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

• the holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the requirements above.

101

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:

• cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the old notes in the exchange offer; and

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

Each broker-dealer that receives new notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of new notes received in exchange for old notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the new notes to be received in the exchange offer.

In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

Exchange agent

Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

WELLS FARGO BANK, NATIONAL ASSOCIATION

By Facsimile for Eligible Institutions: (214) 777-4086 Attention: Ms. Nancye Patterson By Mail/Overnight Delivery/Hand: Wells Fargo Bank, National Association. 1445 Ross Ave., 2nd Floor Dallas, Texas 75202 Attention: Ms. Nancye Patterson Confirm By Telephone: (214) 777-4078

102

DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.

Fees and expenses

The expenses of soliciting tenders pursuant to this exchange offer will be paid by us. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of old notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, new notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the old notes tendered, or if a transfer tax is imposed for any reason other than the exchange of old notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Transfer taxes

We will pay all transfer taxes, if any, applicable to the exchange of old 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 old notes under the exchange offer.

Consequences of failure of exchange outstanding securities

Holders who desire to tender their old notes in exchange for new notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor us is under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange.

Old notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of old notes, we will have no further obligation to provide for the registration under the Securities Act of such old notes. In general, old notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We do not currently anticipate that we will take any action to register the old notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders

103

of the old notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances.

Holders of the new notes issued in the exchange offer, any old notes which remain outstanding after completion of the exchange offer and the previously issued notes will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Accounting treatment

We will record the new notes at the same carrying value as the old notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the new notes.

Other

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

104

Description of the new notes

We issued the old notes under an Indenture (the “Indenture”) among us, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”). We will issue the new notes under the same Indenture under which we issued the old notes, and the new notes will represent the same debt as the old notes for which they are exchanged.

The Indenture is governed by the Trust Indenture Act of 1939 (the “Trust Indenture Act”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act.

Under the Indenture, we may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). We will only be permitted to issue such Additional Notes in compliance with the covenant described under the subheading “—Certain covenants—Limitations on Indebtedness and Preferred Stock.” Any Additional Notes will be part of the same issue as the Notes and will vote on all matters with the holders of the Notes.

Old notes that remain outstanding after the completion of the exchange offer, together with the new notes, will be treated as a single class of securities under the Indenture. Unless the context otherwise requires, for all purposes of the Indenture and this “Description of the new notes,” references to the Notes include the old notes, the new notes and any Additional Notes actually issued, and all references to specified percentages in aggregate principal amount of the notes shall be deemed to mean, at any time after the exchange offer is completed, such percentage in aggregate principal amount of the old notes and the new notes then outstanding.

The terms of the new notes will be substantially identical to the terms of the old notes, except that the new notes:

• will have been registered under the Securities Act;

• will not be subject to transfer restrictions applicable to the old notes; and

• will not have the benefit of the registration rights agreement applicable to the old notes.

The following description is intended to be a useful overview of the material provisions of the Notes, the Indenture, and the Registration Rights Agreement. Since this description of notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights.

You will find the definitions of capitalized terms used in this description of notes under the heading “Certain definitions.” For purposes of this description, references to “the Company,” “we,” “our” and “us” refer only to Chaparral Energy, Inc. and not to any of its subsidiaries.

General

The Notes.    The Notes:

• are general unsecured, senior obligations of the Company;

• mature on December 1, 2015;

• will be issued in denominations of $2,000 and integral multiples of $2,000;

• will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form, see “Book-entry, delivery and form”;

105

• rank senior in right of payment to all existing and future Subordinated Obligations of the Company;

• rank equally in right of payment to any future senior Indebtedness of the Company, without giving effect to collateral arrangements;

• are currently unconditionally guaranteed on a senior basis by Triumph Tools & Supply, L.L.C., Chaparral Texas, L.P., Chaparral Real Estate, L.L.C., Chaparral Resources, L.L.C., Chaparral CO2, L.L.C., NorAm Petroleum, L.L.C., Chaparral Energy, L.L.C. and CEI Acquisition, L.L.C. representing each direct and indirect wholly-owned subsidiary of the Company, see “Subsidiary guarantees”; and

• effectively rank junior to any existing or future secured Indebtedness of the Company, including amounts that may be borrowed under our Senior Secured Credit Agreement, to the extent of the value of the collateral securing such Indebtedness.

Interest.    Interest on the Notes will compound semi-annually and will:

• accrue at the rate of 8 ¹/2% per annum;

• accrue from the Issue Date or, if interest has already been paid, from the most recent interest payment date;

• be payable in cash semi-annually in arrears on June 1 and December 1, commencing on June 1, 2006;

• be payable to the holders of record on the May 15 and November 15 immediately preceding the related interest payment dates; and

• be computed on the basis of a 360-day year comprised of twelve 30-day months.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no liquidated damages will accrue as a result of such delayed payment. The Company will pay interest on overdue principal of the Notes at 0.5 percentage points per annum in excess of the above rate, and overdue installments of interest at such higher rate, to the extent lawful.

We also will pay liquidated damages to holders of the Notes if we fail to complete the exchange offer described in the Registration Rights Agreement within 270 days of the closing date of the old notes or if certain other conditions contained in the Registration Rights Agreement are not satisfied. All references in the Indenture, in any context, to any interest or other amount payable on or with respect to the Notes shall be deemed to include any liquidated damages pursuant to the Registration Rights Agreement.

Payments on the notes; paying agent and registrar

We will pay principal of, premium, if any, liquidated damages, if any, and interest on the Notes at the office or agency designated by the Company in the City and State of New York, except that we may, at our option, pay interest on the Notes by check mailed to holders of the Notes at their registered address as it appears in the registrar’s books. We have initially designated the corporate trust office of the Trustee in New York, New York to act as our paying agent and

106

registrar. We may, however, change the paying agent or registrar without prior notice to the holders of the Notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

We will pay principal of, premium, if any, liquidated damages, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and exchange

A holder may transfer or exchange Notes in accordance with 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. No service charge will be imposed by the Company, the Trustee or the registrar for any registration of transfer or exchange of Notes, but the Company may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered holder of a Note will be treated as the owner of it for all purposes.

Optional redemption

On and after December 1, 2010, we may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of the Notes) plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning December 1 on of the years indicated below:

Year	Percentage
2010	104.250%
2011	102.833%
2012	101.417%
2013 and thereafter	100.000%

Prior to December 1, 2008 we may, at our option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes (including Additional Notes) issued under the Indenture with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 108.500% of the principal amount thereof, plus accrued and unpaid interest, if any, and liquidated damages, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1) at least 65% of the original principal amount of the Notes issued on the Issue Date remains outstanding after each such redemption; and

107

(2) the redemption occurs within 90 days after the closing of the related Equity Offering.

In addition, the Notes may be redeemed, in whole or in part, at any time prior to December 1, 2010 at the option of the Company upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder of Notes at its registered address, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date). “Applicable Premium” means, with respect to any Note on any applicable redemption date, the greater of:

(1) 1.0% of the principal amount of such Note; and

(2) the excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such Note at December 1, 2010 (such redemption price being set forth in the table appearing above under the caption “Optional redemption”) plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such Note through December 1, 2010, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such Note.

“Treasury Rate” means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which 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 or similar market data)) most nearly equal to the period from the redemption date to December 1, 2010; provided, however, that if the period from the redemption date to December 1, 2010 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to December 1, 2010 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

Selection and notice

If the Company is redeeming less than all of the outstanding Notes, the Trustee will select the Notes for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed or, if the Notes are not listed, then on a pro rata basis, by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no Note of $2,000 in original principal amount or less will be redeemed in part. If any Note is to be redeemed in part only, the notice of redemption relating to such Note will state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the partially redeemed Note. On and after the redemption date, interest will cease to accrue on Notes or the portion of them called for redemption unless we default in the payment thereof.

108

Mandatory redemption; Offers to purchase; Open market purchases

We are not required to make mandatory redemption payments or sinking fund payments with respect to the Notes. However, under certain circumstances, we may be required to offer to purchase Notes as described under the captions “—Change of control” and “—Certain covenants—Limitation on sales of assets and Subsidiary stock.”

We may acquire Notes by means other than a redemption, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture. However, other existing or future agreements of the Company may limit the ability of the Company or its Subsidiaries to purchase Notes prior to maturity.

Ranking

The Notes will be general unsecured obligations of the Company that rank senior in right of payment to all existing and future Indebtedness that is expressly subordinated in right of payment to the Notes. The Notes will rank equally in right of payment with all existing and future liabilities of the Company that are not so subordinated and will be effectively subordinated to all of our secured Indebtedness (to the extent of the value of the collateral securing such Indebtedness) and liabilities of any of our Subsidiaries that do not guarantee the Notes. In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary Guarantees only after all Indebtedness under such Credit Facility and other secured Indebtedness has been repaid in full from such assets. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

As of March 31, 2006:

• we and our Subsidiary Guarantors had approximately $472.0 million of total Indebtedness; and

• of the approximately $472.0 million of total Indebtedness, approximately $134.0 million constituted secured Indebtedness under our Senior Secured Credit Agreement and we had additional availability of $37.5 million under our Senior Secured Credit Agreement as to which the Notes were effectively subordinated to the extent of the assets secured thereby.

Subsidiary guarantees

The Subsidiary Guarantors, as primary obligors and not merely as sureties, will, jointly and severally, irrevocably and unconditionally guarantee on a senior unsecured basis our obligations under the Notes and all obligations under the Indenture. The obligations of Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinate to the obligations arising under the Subsidiary Guarantee.

As of March 31, 2006, outstanding Indebtedness of Subsidiary Guarantors was $472.0 million, of which $147.0 million was secured.

109

Although the Indenture limits the amount of Indebtedness that Restricted Subsidiaries may Incur, such Indebtedness may be substantial and such limitation is subject to a number of significant qualifications. Moreover, the Indenture does not impose any limitation on the Incurrence by such Subsidiaries of liabilities that are not considered Indebtedness under the Indenture. See “—Certain covenants—Limitation on Indebtedness and Preferred Stock.”

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. See “Risk factors—A subsidiary guarantee could be voided if it constitutes a fraudulent transfer under U.S. bankruptcy or similar state law, which would prevent the holders of the notes from relying on that subsidiary to satisfy claims.” If a Subsidiary Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor’s liability on its Subsidiary Guarantee could be reduced to zero. If the obligations of a Subsidiary Guarantor under its Subsidiary Guarantee were avoided, holders of Notes would have to look to the assets of any remaining Subsidiary Guarantors for payment. There can be no assurance in that event that such assets would suffice to pay the outstanding principal and interest on the Notes.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of its Capital Stock or the sale of all or substantially all of its assets (other than by lease)) and whether or not the Subsidiary Guarantor is the surviving corporation in such transaction to a Person which is not the Company or a Restricted Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “Certain covenants—Limitation on sales of assets and Subsidiary stock.”

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture, its Subsidiary Guarantee and the Registration Rights Agreement if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or in connection with any legal defeasance or satisfaction and discharge of the Notes as provided below under the captions “Defeasance” and “Satisfaction and discharge.”

Change of control

If a Change of Control occurs, unless the Company has previously or concurrently exercised its right to redeem all of the Notes as described under “Optional redemption,” each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple thereof) of such holder’s Notes at a purchase price in cash equal to 101% of the principal amount of the Notes plus accrued and unpaid interest, if any, and liquidated damages, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless we have previously or concurrently exercised our right to redeem all of the Notes as described under “Optional redemption,” we will mail a notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require us to purchase such holder’s Notes at a purchase price in cash equal to 101% of the principal

110

amount of such Notes plus accrued and unpaid interest, if any, and liquidated damages, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”);

(3) that any Note not properly tendered will remain outstanding and continue to accrue interest;

(4) that unless we default in the payment of the Change of Control Payment, all Notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) that holders electing to have any Notes purchased pursuant to a Change of Control Offer will be required to surrender such Notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of such Notes completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) that holders will be entitled to withdraw their tendered Notes and their election to require us to purchase such Notes, provided that the paying agent receives, not later than the close of business on the 30th day following the date of the Change of Control notice, a telegram, telex, facsimile transmission or letter setting forth the name of the holder of the Notes, the principal amount of Notes tendered for purchase, and a statement that such holder is withdrawing its tendered Notes and its election to have such Notes purchased;

(7) that if we are redeeming less than all of the Notes, the holders of the remaining Notes will be issued new Notes and such new Notes will be equal in principal amount to the unpurchased portion of the Notes surrendered. The unpurchased portion of the Notes must be equal to $2,000 or an integral multiple thereof; and

(8) the procedures determined by us, consistent with the Indenture, that a holder must follow in order to have its Notes repurchased.

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (in integral multiples of $2,000) 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 not properly withdrawn; and

(3) deliver or cause to be delivered to the Trustee the Notes so 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 and not properly withdrawn 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; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple thereof.

111

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, and liquidated damages, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no further interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above 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 to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

We will not be required to make a Change of Control Offer upon a Change of Control if 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 us and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer.

We will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, or compliance with the Change of Control provisions of the Indenture would constitute a violation of any such laws or regulations, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations described in the Indenture by virtue of our compliance with such securities laws or regulations.

Our ability to repurchase Notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement will not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repurchased upon a Change of Control. Moreover, the exercise by the holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. Finally, the Company’s ability to pay cash to the holders upon a repurchase may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the terms of the Senior Secured Credit Agreement will, and other an/or future Indebtedness may, prohibit the Company’s prepayment or repurchase of Notes before their scheduled maturity. Consequently, if the Company is not able to prepay the Indebtedness under the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite consents, the Company will be unable to fulfill its repurchase obligations if holders of Notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

112

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company. The Change of Control purchase feature is a result of negotiations between the initial purchasers and us. As of the Issue Date, we have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to do so in the future. Subject to the limitations discussed below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to incur additional Indebtedness are contained in the covenants described under “Certain covenants—Limitation on Indebtedness and Preferred Stock” and “Certain covenants—Limitation on Liens.” Such restrictions in the Indenture can be waived only with the consent of the holders of a majority in principal amount of the Notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture does not contain any covenants or provisions that may afford holders of the Notes protection in the event of a highly leveraged transaction.

The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person other than a Permitted Holder. 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, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property or assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above.

The provisions under the Indenture relative to our obligation to make an offer to repurchase the Notes as a result of a Change of Control may be waived or modified or terminated with the written consent of the holders of a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the Notes) prior to the occurrence of such Change of Control.

Certain covenants

Limitation on Indebtedness and Preferred Stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness) and the Company will not permit any of its Restricted Subsidiaries to issue Preferred Stock; provided, however, that the Company may Incur Indebtedness and any of the Subsidiary Guarantors may Incur Indebtedness and issue Preferred Stock if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.00 to 1.00, determined on a pro forma basis (including a pro forma application of proceeds); and

(2) no Default will have occurred or be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

113

The first paragraph of this covenant will not prohibit the Incurrence of the following Indebtedness:

(1) Indebtedness of the Company Incurred pursuant to one or more Credit Facilities in an aggregate amount not to exceed the greater of (a) $200.0 million less the aggregate amount of all permanent principal repayments since the Issue Date under a Credit Facility that are made under clause or 3(a) of the first paragraph of the covenant described under “Certain covenants—Limitation on sales of assets and Subsidiary stock,” or (b) 30% of Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom, in each case outstanding at any one time;

(2) Guarantees by the Company or Subsidiary Guarantors of Indebtedness of the Company or a Subsidiary Guarantor, as the case may be, Incurred in accordance with the provisions of the Indenture; provided that in the event such Indebtedness that is being Guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related Guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantee to at least the same extent as the Indebtedness being Guaranteed, as the case may be;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however, that (i) any subsequent issuance or transfer of Capital Stock or any other event which 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 other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be;

(4) Indebtedness represented by (a) the Notes issued on the Issue Date, and the related exchange notes issued in a registered exchange offer (or shelf registration) pursuant to the Registration Rights Agreement, and all Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2) and 4(a)) outstanding on the Issue Date and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or Incurred pursuant to the first paragraph of this covenant;

(5) Indebtedness of a Person that becomes a Restricted Subsidiary or is acquired by the Company or a Restricted Subsidiary or merged into the Company or a Restricted Subsidiary in accordance with the Indenture and outstanding on the date on which such Person became a Restricted Subsidiary or was acquired by or was merged into the Company or such Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Person became a Restricted Subsidiary or was otherwise acquired by or was merged into the Company or a Restricted Subsidiary or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Person becomes a Restricted Subsidiary or is acquired by or was merged into the Company or a Restricted Subsidiary, the Company would have been able to Incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the Incurrence of such Indebtedness pursuant to this clause (5);

114

(6) the Incurrence by the Company or any Restricted Subsidiary of Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations, in each case Incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements or carrying costs of property used in the business of the Company or such Restricted Subsidiary, and Refinancing Indebtedness Incurred to Refinance any Indebtedness Incurred pursuant to this clause (6) in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (6) and then outstanding, will not exceed $20 million at any time outstanding;

(7) Indebtedness Incurred in respect of (a) self-insurance obligations, bid, appeal, reimbursement, performance, surety and similar bonds and completion guarantees provided by the Company or a Restricted Subsidiary in the ordinary course of business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations and (b) obligations represented by letters of credit for the account of the Company or a Restricted Subsidiary in order to provide security for workers’ compensation claims (in the case of clauses (a) and (b) other than for an obligation for money borrowed);

(8) Capital Stock (other than Disqualified Stock) of the Company or of any of the Subsidiary Guarantors;

(9) Indebtedness, including Refinancing Indebtedness, Incurred by a Foreign Subsidiary in an aggregate amount not to exceed 15% of such Foreign Subsidiary’s Adjusted Consolidated Net Tangible Assets at any time outstanding;

(10) Any Guarantee by the Company or any Restricted Subsidiary that directly owns Capital Stock of the Ethanol Subsidiary that is recourse only to, or secured only by, such Capital Stock; and

(11) in addition to the items referred to in clauses (1) through (10) above, Indebtedness of the Company and its Subsidiary Guarantors in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (11) and then outstanding, will not exceed $30 million at any time outstanding.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event an item of that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below may later reclassify such item of Indebtedness and only be required to include the amount and type of such Indebtedness in one of such clauses;

(2) all Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed Incurred on the Issue Date under clause (1) of the second paragraph of this covenant;

(3) Guarantees of, or obligations in respect of letters of credit supporting, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

115

(4) if obligations in respect of letters of credit are Incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;

(5) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(6) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

(7) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the amortization of debt discount or the accretion of accreted value, the payment of interest in the form of additional Indebtedness, the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of FAS 133) will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on Indebtedness and Preferred Stock” covenant, the Company shall be in Default of this covenant).

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

116

The Indenture does not treat (1) unsecured Indebtedness as subordinated or junior to secured Indebtedness merely because it is unsecured or (2) senior Indebtedness as subordinated or junior to any other senior Indebtedness merely because it has a junior priority with respect to the same collateral.

Limitation on Restricted Payments

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

(1) declare or pay any dividend or make any payment or distribution on or in respect of the Company’s Capital Stock (including any payment or distribution in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions by the Company payable solely in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary and if such Restricted Subsidiary is not a Wholly-Owned Subsidiary, to minority stockholders (or owners of an equivalent interest in the case of a Subsidiary that is an entity other than a corporation) so long as the Company or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution;

(2) purchase, redeem, defease, retire or otherwise acquire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Restricted Subsidiary (other than in exchange for Capital Stock of the Company (other than Disqualified Stock));

(3) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness permitted under clause (3) of the second paragraph of the covenant “—Limitation on indebtedness and Preferred Stock” or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(4) make any Restricted Investment in any Person;

(any such dividend, distribution, purchase, redemption, repurchase, defeasance, other acquisition, retirement or Restricted Investment referred to in clauses (1) through (4) shall be referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(a) a Default shall have occurred and be continuing (or would result therefrom);

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the covenant described under the first paragraph under “—Limitation on Indebtedness and Preferred Stock” after giving effect, on a pro forma basis, to such Restricted Payment; or

117

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date would exceed the sum of:

(i) 50% of Consolidated Net Income for the period (treated as one accounting period) from October 1, 2005 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which internal financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds, and the fair market value (as determined by the Company’s Board of Directors in good faith) of property or securities other than cash (including Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business), in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to (x) management, employees, directors or any direct or indirect parent of the Company, to the extent such Net Cash Proceeds have been used to make a Restricted Payment pursuant to clause (5)(a) of the next succeeding paragraph, (y) a Subsidiary of the Company or (z) an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination));

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Wholly-Owned Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the fair market value of any other property (other than such Capital Stock), distributed by the Company upon such conversion or exchange), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; and

(iv) the amount equal to the aggregate net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any Person resulting from:

(A) repurchases, repayments or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investment (other than to a Subsidiary of the Company), repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary;

(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary, which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income; and

(C) the sale (other than to the Company or a Restricted Subsidiary) of the Capital Stock of an Unrestricted Subsidiary or a distribution from an Unrestricted Subsidiary or a dividend from an Unrestricted Subsidiary.

118

The provisions of the preceding paragraph will not prohibit:

(1) any Restricted Payment made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary or an employee stock ownership plan or similar trust to the extent such sale to an employee stock ownership plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) or a substantially concurrent cash capital contribution received by the Company from its shareholders; provided, however, that (a) such Restricted Payment will be excluded from subsequent calculations of the amount of Restricted Payments and (b) the Net Cash Proceeds from such sale of Capital Stock or capital contribution will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated Obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(3) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(4) dividends paid or distributions made within 60 days after the date of declaration if at such date of declaration such dividend or distribution would have complied with this covenant; provided, however, that such dividends and distributions will be included in subsequent calculations of the amount of Restricted Payments; and provided, however, that for purposes of clarification, this clause (4) shall not include cash payments in lieu of the issuance of fractional shares included in clause (9) below;

(5) (a)(i) the purchase, redemption or other acquisition, cancellation or retirement for value (each, a “Purchase”) of phantom units under the Phantom Unit Plan held by any existing or former employees, management or directors of Parent, the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under the Phantom Unit Plan; or (ii) so long as no Default has occurred and is continuing, the Purchase of Capital Stock, or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of Parent, the Company or any Restricted Subsidiary (other than Purchases covered by subclause (a)(i) above) held by any existing or

119

former employees, management or directors of Parent, the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate management, employees or directors; provided that such redemptions or repurchases pursuant to this subclause (a)(ii) during any calendar year will not exceed $2.0 million in the aggregate (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum (without giving effect to the immediately following proviso) of $3.0 million in any calendar year); provided further, that such amount in any calendar year may be increased by an amount not to exceed (A) the cash proceeds received by the Company from the sale of Capital Stock of the Company to members of management or directors of the Company and its Restricted Subsidiaries that occurs after the Issue Date (to the extent the cash proceeds from the sale of such Capital Stock have not otherwise been applied to the payment of Restricted Payments by virtue of the clause (c) of the preceding paragraph), plus (B) the cash proceeds of key man life insurance policies received by the Company and its Restricted Subsidiaries after the Issue Date, less (C) the amount of any Restricted Payments made pursuant to clauses (A) and (B) of this clause (5)(a); provided further, however, that the amount of any such repurchase or redemption under each of subclauses (a)(i) and (a)(ii) will be excluded in subsequent calculations of the amount of Restricted Payments and the proceeds received from any such sale will be excluded from clause (c)(ii) of the preceding paragraph; and

(b) the cancellation of loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $2.0 million at any one time outstanding; provided, however, that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances; provided, further, that the amount of such cancelled loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(6) repurchases, redemptions or other acquisitions or retirements for value of Capital Stock deemed to occur upon the exercise of stock options, warrants, rights to acquire Capital Stock or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof, and any repurchases, redemptions or other acquisitions or retirements for value of Capital Stock made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Capital Stock; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

(7) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the covenant described under “Change of control” or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the covenant described under “—Limitation on sales of assets and Subsidiary stock”; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the Notes and has completed the repurchase or redemption of all

120

Notes validly tendered for payment in connection with such Change of Control Offer or Asset Disposition Offer; provided, however, that such repurchases will be included in subsequent calculations of the amount of Restricted Payments;

(8) payments or distributions to dissenting stockholders pursuant to applicable law or in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets; provided, however, that any payment pursuant to this clause (8) shall be included in the calculation of the amount of Restricted Payments;

(9) cash payments in lieu of the issuance of fractional shares; provided, however, that any payment pursuant to this clause (9) shall be excluded in the calculation of the amount of Restricted Payments;

(10) Permitted Payments to Parent;

(11) Restricted Payments in an amount not to exceed $10.0 million at any one time outstanding; provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The fair market value of any cash Restricted Payment shall be its face amount and the fair market value of any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith whose resolution with respect thereto shall be delivered to the Trustee, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if such fair market value is estimated in good faith by the Board of Directors of the Company to exceed $20.0 million. Not later than the date of making any Restricted Payment, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant described under “Restricted Payments” were computed, together with a copy of any fairness opinion or appraisal required by the Indenture.

As of the Issue Date, all of our Subsidiaries other than the Ethanol Subsidiary will be Restricted Subsidiaries. We will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary.” For purpose of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investment.” Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (11) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments,” and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not be subject to any of the restrictive covenants set forth in the Indenture.

Limitation on Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (the “Initial Lien”) other than Permitted Liens

121

upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), including any income or profits therefrom, whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Liens effective provision is made to secure the Indebtedness due under the Notes or, in respect of Liens on any Restricted Subsidiary’s property or assets, any Subsidiary Guarantee of such Restricted Subsidiary, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

Any Lien created for the benefit of the holders of the Notes pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the release and discharge of the Initial Lien.

Limitation on restrictions on distributions from Restricted Subsidiaries

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

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

(2) make any loans or advances to the Company or any Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

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

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to or by reason of an agreement in effect at or entered into on the Issue Date, including, without limitation, the Indenture in effect on such date;

(ii) any encumbrance or restriction with respect to a Person pursuant to or by reason of an agreement relating to any Capital Stock or Indebtedness Incurred by a Person on or before the date on which such Person was acquired by the Company or another Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Person was acquired by the Company or a Restricted Subsidiary or in contemplation of the transaction) and outstanding on such date; provided, that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

122

(iii) encumbrances and restrictions contained in contracts entered into in the ordinary course of business, not relating to any Indebtedness, and that do not, individually or in the aggregate, detract from the value of, or from the ability of the Company and the Restricted Subsidiaries to realize the value of, property or assets of the Company or any Restricted Subsidiary in any manner material to the Company or any Restricted Subsidiary;

(iv) any encumbrance or restriction with respect to a Unrestricted Subsidiary pursuant to or by reason of an agreement that the Unrestricted Subsidiary is a party to entered into before the date on which such Unrestricted Subsidiary became a Restricted Subsidiary; provided, that such agreement was not entered into in anticipation of the Unrestricted Subsidiary becoming a Restricted Subsidiary and any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(v) with respect to any Foreign Subsidiary, any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was Incurred if:

(a) either (1) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (2) the Company determines that any such encumbrance or restriction will not materially affect the Company’s ability to make principal or interest payments on the Notes, as determined in good faith by the Board of Directors of the Company, whose determination shall be conclusive; and

(b) the encumbrance or restriction is not materially more disadvantageous to the holders of the Notes than is customary in comparable financing (as determined by the Company);

(vi) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi) or contained in any amendment, restatement, modification, renewal, supplemental, refunding, replacement or refinancing of an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in such agreements referred to in clauses (i) through (v) or clause (xii) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary or was merged into a Restricted Subsidiary, whichever is applicable;

(vii) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in oil and gas properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in oil and gas properties), license or other contract;

123

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;

(c) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

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

(e) provisions with respect to the disposition or distribution of assets or property in operating agreements, joint venture agreements, development agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and entered into in the ordinary course of business.

(viii) (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations permitted under the Indenture, in each case, that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property so acquired;

(ix) any encumbrance or restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or disposition of all or substantially all the Capital Stock or assets of such Restricted Subsidiary (or the property or assets that are subject to such restriction) pending the closing of such sale or disposition;

(x) any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Permitted Business Investment”;

(xi) encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order; and

(xii) the Senior Secured Credit Agreement as in effect as of the Issue Date, and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings thereof, provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are no more restrictive with respect to such dividend and other payment restrictions than those contained in the Senior Secured Credit Agreement as in effect on the Issue Date.

Limitation on sales of assets and Subsidiary stock

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Disposition at least equal to the fair market value (such fair market value to be determined on the date of contractually agreeing to such Asset Disposition), as determined in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition;

(2) at least 75% of the consideration received by the Company or such Restricted Subsidiary, as the case may be, from such Asset Disposition is in the form of cash or Cash Equivalents or

124

Additional Assets, or any combination thereof; and

(3) except as provided in the next paragraph an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied, within one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, by the Company or such Restricted Subsidiary, as the case may be:

(a) to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Indebtedness), to prepay, repay, redeem or purchase Indebtedness of the Company under the Senior Secured Credit Agreement, any other Indebtedness of the Company or a Subsidiary Guarantor that is secured by a Lien permitted to be Incurred under the Indenture or Indebtedness (other than Disqualified Stock) of any Wholly-Owned Subsidiary that is not a Subsidiary Guarantor; provided, however, that, in connection with any prepayment, repayment, redemption or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased; or

(b) to invest in Additional Assets;

provided that pending the final application of any such Net Available Cash in accordance with this covenant, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds.” Not later than the day following the date that is one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $15.0 million, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount (or, in the event such Pari Passu Indebtedness of the Company was issued with significant original issue discount, 100% of the accreted value thereof) of the Notes and Pari Passu Notes plus accrued and unpaid interest and liquidated damages, if any, (or in respect of such Pari Passu Indebtedness, such lesser price, if any, as may be provided for by the terms of such Indebtedness) to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in integral multiples of $2,000. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate

125

purposes, subject to the other covenants contained in the Indenture. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest and liquidated damages, if any, will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no further interest or liquidated damages will be payable to holders who tender Notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of Notes and Pari Passu Notes or portions of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all Notes and Pari Passu Notes so validly tendered and not properly withdrawn, in each case in integral multiples of $2,000. The Company will deliver to the Trustee an Officers’ Certificate stating that such Notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates and notes required, if any, by the agreements governing the Pari Passu Notes. The Company or the paying agent, as the case may be, will promptly (but in any case not later than five Business Days after the termination of the Asset Disposition Offer Period) mail or deliver to each tendering holder of Notes or holder or lender of Pari Passu Notes, as the case may be, an amount equal to the purchase price of the Notes or Pari Passu Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers’ Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $2,000. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

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

126

For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness (other than Subordinated Obligations or Disqualified Stock) of the Company or Indebtedness of a Restricted Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Restricted Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (or in lieu of such a release, the agreement of the acquirer or its parent company to indemnify and hold the Company or such Restricted Subsidiary harmless from and against any loss, liability or cost in respect of such assumed Indebtedness; provided, however, that such indemnifying party (or its long term debt securities) shall have an Investment Grade Rating (with no indication of a negative outlook or credit watch with negative implications, in any case, that contemplates such indemnifying party (or its long term debt securities) failing to have an Investment Grade Rating), in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) of the first paragraph of this covenant; and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 90 days after receipt thereof.

Notwithstanding the foregoing, the 75% limitation referred to in clause (2) of the first paragraph of this covenant shall be deemed satisfied with respect to any Asset Disposition in which the cash or Cash Equivalents portion of the consideration received therefrom, determined in accordance with the foregoing provision on an after-tax basis, is equal to or greater than what the after-tax proceeds would have been had such Asset Disposition complied with the aforementioned 75% limitation.

The requirement of clause (3)(b) of the first paragraph of this covenant above shall be deemed to be satisfied if an agreement (including a lease, whether a capital lease or an operating lease) committing to make the acquisitions or expenditures referred to therein is entered into by the Company or its Restricted Subsidiary within the specified time period and such Net Available Cash is subsequently applied in accordance with such agreement within six months following such agreement.

Limitation on Affiliate Transactions

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into, make, amend or conduct any transaction (including making a payment to, the purchase, sale, lease or exchange of any property or the rendering of any service), contract, agreement or understanding with or for the benefit of any Affiliate of the Company (an “Affiliate Transaction”) unless:

(1) the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate;

(2) if such Affiliate Transaction involves an aggregate consideration in excess of $5.0 million, the terms of such transaction have been approved by a majority of the members of the

127

Board of Directors of the Company and by a majority of the members of such Board having no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) if such Affiliate Transaction involves an aggregate consideration in excess of $20.0 million, the Board of Directors of the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of nationally recognized standing that such Affiliate Transaction is fair, from a financial standpoint, to the Company or such Restricted Subsidiary or is not materially less favorable than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

The preceding paragraph will not apply to:

(1) any Restricted Payment permitted to be made pursuant to the covenant described under “—Limitation on Restricted Payments”;

(2) any issuance of Capital Stock (other than Disqualified Stock), or other payments, awards or grants in cash, Capital Stock (other than Disqualified Stock) or otherwise pursuant to, or the funding of, employment or severance agreements and other compensation arrangements, options to purchase Capital Stock (other than Disqualified Stock) of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans and/or indemnity provided on behalf of officers and employees approved by the Board of Directors of the Company;

(3) loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(4) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries and Guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with “—Limitations on Indebtedness”;

(5) any transaction with a joint venture or similar entity which would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns, directly or indirectly, an equity interest in or otherwise controls such joint venture or similar entity;

(6) the issuance or sale of any Capital Stock (other than Disqualified Stock) of the Company or the receipt by the Company of any capital contribution from its shareholders;

(7) indemnities of officers, directors and employees of the Company or any of its Restricted Subsidiaries permitted by bylaw or statutory provisions and any employment agreement or other employee compensation plan or arrangement entered into in the ordinary course of business by the Company or any of its Restricted Subsidiaries;

(8) the payment of reasonable compensation and fees paid to, and indemnity provided on behalf of, officers or directors of the Company or any Restricted Subsidiary;

(9) the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future

128

amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted to the extent that its terms are not materially more disadvantageous, taken as a whole, to the holders of the Notes than the terms of the agreements in effect on the Issue Date; and

(10) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture which are fair to the Company and its Restricted Subsidiaries, in the reasonable determination of the board of directors of the Company or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party.

SEC reports

The Indenture provides that, whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, to the extent not prohibited by the Exchange Act, the Company will file with the SEC, and make available to the Trustee and the registered holders of the Notes without cost to any holder, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation within the time periods specified therein with respect to a non-accelerated filer. In the event that the Company is not permitted to file such reports, documents and information with the SEC pursuant to the Exchange Act, the Company will nevertheless make available such Exchange Act information to the Trustee and the holders of the Notes without cost to any holder as if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein with respect to a non-accelerated filer.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management’s Discussion and Analysis of Results of Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

In addition, the Company and the Subsidiary Guarantors have agreed that they will make available to the holders and to prospective investors, upon the request of such holders, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the Notes are not freely transferable under the Securities Act to the extent not satisfied by the foregoing. For purposes of this covenant, the Company and the Subsidiary Guarantors will be deemed to have furnished the reports to the Trustee and the holders of Notes as required by this covenant if it has filed such reports with the SEC via the EDGAR filing system and such reports are publicly available.

Notwithstanding the foregoing, such requirements shall be deemed satisfied prior to the commencement of the exchange offer or the effectiveness of the shelf registration statement by the filing with the SEC of the exchange offer registration statement or shelf registration statement, and any amendments thereto, with such financial information that satisfies Regulation S-X of the Securities Act within the time period specified by the Registration Rights Agreement.

129

Merger and consolidation

The Company will not consolidate with or merge with or into or wind up into (whether or not the Company is the surviving corporation), or convey, transfer or lease all or substantially all its assets in one or more related transactions to, any Person, unless:

(1) the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Company under the Notes, the Indenture and the Registration Rights Agreement (if applicable);

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default shall have occurred and be continuing;

(3) immediately after giving effect to such transaction, the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “—Limitation on Indebtedness and Preferred Stock”;

(4) each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations in respect of the Indenture and the Notes and its obligations under the Registration Rights Agreement (if applicable) shall continue to be in effect; and

(5) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer, or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture; and its predecessor Company, except in the case of a lease of all or substantially all its assets, will be released from the obligation to pay the principal of and interest on the Notes.

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, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the property or assets of a Person.

130

Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company and the Company may consolidate with, merge into or transfer all or part of its properties and assets to a Wholly-Owned Subsidiary and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction; provided that, in the case of a Restricted Subsidiary that consolidates with, merges into or transfers all or part of its properties and assets to the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, and will not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor to, any Person (other than the Company or another Subsidiary Guarantor) unless:

(1) (a) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee and (b) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default shall have occurred and be continuing; or

(2) the transaction is made in compliance with the covenants described under “Subsidiary Guarantees” and “Certain Covenants—Limitation on sales of assets and Subsidiary stock.”

Future Subsidiary Guarantors

The Indenture provides that the Company will cause each Restricted Subsidiary that Incurs any Indebtedness other than a Foreign Subsidiary created or acquired by the Company or one or more of its Restricted Subsidiaries to execute and deliver to the Trustee a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, interest and liquidated damages, if any, on the Notes on a senior basis; provided that any Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Subsidiary Guarantor until such time as it ceases to be an Immaterial Subsidiary.

Limitation on lines of business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to the extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Payments for consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or

131

provisions of the Indenture or the Notes unless such consideration is offered to be paid or 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 amendment.

Events of default

Each of the following is an Event of Default:

(1) default in any payment of interest or liquidated damages (as required by the Registration Rights Agreement) on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration of acceleration or otherwise;

(3) failure by the Company or any Subsidiary Guarantor to comply with its obligations under “Certain covenants—Merger and consolidation”;

(4) failure by the Company to comply for 30 days after notice as provided below with any of its obligations under the covenant described under “Change of Control” above or under the covenants described under “Certain covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “Certain covenants—Merger and consolidation” which is covered by clause (3));

(5) failure by the Company to comply for 60 days after notice as provided below with its other agreements contained in the Indenture;

(6) 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), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which 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 (and any extensions of any grace period) (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its maturity (the “cross acceleration provision”);

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 $15.0 million or more;

(7) certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the

132

Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $15.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid or discharged, and there shall be any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, shall not be in effect (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that, taken together (as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company in writing and, in the case of a notice given by the holders, the Trustee of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, accrued and unpaid interest, if any, and liquidated damages, if any, on all the Notes to be due and payable. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, accrued and unpaid interest and liquidated damages, if any, on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium, interest or liquidated damages, if any) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if 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 of the holders 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 when due, no holder 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 principal amount of the outstanding Notes have requested the Trustee to pursue the remedy;

133

(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) the holders of a majority in principal amount of the outstanding Notes have not waived such Event of Default or otherwise given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

Amendments and waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in 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, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in 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). However, without the consent of each holder of an outstanding Note affected, no amendment may, among other things:

(1) reduce the principal amount of Notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption of any Note as described above under “Optional redemption,” or change the time at which any Note may be redeemed as

134

described above under “Optional redemption,” or make any change to the covenants described above under “Change of Control” after the occurrence of a Change of Control, or make any change to the provisions relating an Asset Disposition Offer that has been made, in each case whether through an amendment or waiver of provisions in the covenants, definitions or otherwise;

(5) make any Note payable in money other than that stated in the Note;

(6) impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(8) modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes; or

(9) make any change to or modify the ranking of the Notes that would adversely affect the holders.

Notwithstanding the foregoing, without the consent of any holder, the Company, the Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect, mistake or inconsistency;

(2) provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f) (2) (B) of the Code);

(4) add Guarantees with respect to the Notes, including Subsidiary Guarantees, or release a Subsidiary Guarantor from its Subsidiary Guarantee and terminate such Subsidiary Guarantee; provided, however, that the release and termination is in accord with the applicable provisions of the Indenture;

(5) secure the Notes or Subsidiary Guarantees;

(6) add to the covenants of the Company or a Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon the Company or a Subsidiary Guarantor;

(7) make any change that does not adversely affect the rights of any holder;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(9) provide for the issuance of exchange securities which shall have terms substantially identical in all respects to the Notes (except that the transfer restrictions contained in the Notes shall be modified or eliminated as appropriate) and which shall be treated, together with any outstanding Notes, as a single class of securities; or

(10) provide for the succession of a successor Trustee.

135

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. A consent to any amendment or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder’s Notes will not be rendered invalid by such tender. After an amendment under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment.

Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under “Change of Control” and under covenants described under “Certain covenants” (other than “Merger and consolidation”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision and the Subsidiary Guarantee provision described under “Events of default” above and the limitations contained in clause (3) under “Certain covenants—Merger and consolidation” above (“covenant defeasance”).

The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “Events of default” above or because of the failure of the Company to comply with clause (3) under “Certain covenants—Merger and consolidation” above.

In order to exercise either defeasance option, the Company must, among other things, irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

136

Satisfaction and discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when either:

(1) 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 theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and the Company or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for such purpose, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such 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 and accrued interest to the date of maturity or redemption, and in each case certain other requirements set forth in the Indenture are satisfied.

No personal liability of directors, officers, employees and stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

Concerning the trustee

Wells Fargo Bank, National Association, will be the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain definitions

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes or is merged with and into a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person

137

becomes or is merged with and into a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Additional Assets” means:

(1) any properties or assets to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(2) capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” of a Person means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of such Person and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves (including previously estimated development costs Incurred during the period and the accretion of discount since the prior period end) since such year end due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

(C) estimated proved oil and gas reserves produced or disposed of since such year end, and

(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

138

provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s petroleum engineers;

(ii) the capitalized costs that are attributable to oil and gas properties of such Person and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on such Person’s books and records as of a date no earlier than the date of such Person’s latest available annual or quarterly financial statements;

(iii) the Net Working Capital of such Person on a date no earlier than the date of such Person’s latest annual or quarterly financial statements; and

(iv) the greater of

(A) the net book value of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest annual or quarterly financial statement, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest audited financial statements;

minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of such Person and its Restricted Subsidiaries reflected in such Person’s latest audited balance sheet;

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in such Person’s year end reserve report), attributable to reserves which 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 (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of such Person and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the full cost method of accounting.

“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 the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and

139

“controlled” have meanings correlative to the foregoing; provided that beneficial ownership of 10% or more of the Voting Stock of a Person shall be deemed to be control.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of (A) shares of Capital Stock of a Restricted Subsidiary (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary), (B) all or substantially all the assets of any division or line of business of the Company or any Restricted Subsidiary, or (C) any other assets of the Company or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary (each referred to for the purposes of this definition as a “disposition”), in each case by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Wholly-Owned Subsidiary;

(2) the sale of Cash Equivalents in the ordinary course of business;

(3) a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;

(4) a disposition of damaged, unserviceable, obsolete or worn out equipment or equipment that is no longer necessary for the proper conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions in accordance with the covenant described under “Certain covenants—Merger and consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Wholly-Owned Subsidiary;

(7) for purposes of “Certain Covenants—Limitation on sales of assets and Subsidiary stock” only, the making of a Permitted Investment or a Restricted Payment (or a disposition that would constitute a Restricted Payment but for the exclusions from the definition thereof) permitted by the covenant described under “Certain covenants—Limitation on Restricted Payments”;

(8) an Asset Swap;

(9) dispositions of assets with a fair market value of less than $5.0 million;

(10) Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

140

(12) the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property in the ordinary course of business which do not materially interfere with the business of the Company and its Restricted Subsidiaries;

(13) foreclosure on assets;

(14) any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, Incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(15) a disposition of oil and natural gas properties in connection with tax credit transactions complying with Section 29 or any successor or analogous provisions of the Code;

(16) surrender or waiver of contract rights, oil and gas leases, or the settlement, release or surrender of contract, tort or other claims of any kind;

(17) the abandonment, farmout, lease or sublease of developed or undeveloped oil and gas properties in the ordinary course of business; and

(18) the sale or transfer (whether or not in the ordinary course of business) of any oil and gas property or interest therein to which no proved reserves are attributable at the time of such sale or transfer.

“Asset Swap” means any concurrent purchase and sale or exchange of any oil or natural gas property or interest therein between the Company or any of its Restricted Subsidiaries and another Person; provided, that any cash received must be applied in accordance with “Certain covenants—Limitation on sales of assets and Subsidiary stock” as if the Asset Swap were an Asset Disposition.

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“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.

“Board of Directors” means, as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof or as to any Person that is not a corporation, the board of managers or such other individual or group serving a similar function.

“Business Day” means each day that is not a Saturday, Sunday or other day on which commercial banking institutions in New York, New York, Minneapolis, Minnesota or Dallas/Fort Worth, Texas are authorized or required by law to close.

141

“Capital Stock” of any Person means any and all shares, interests, rights to purchase, warrants, options, participation or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

“Capitalized Lease Obligations” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition (provided that the full faith and credit of the United States is pledged in support thereof) and, at the time of acquisition, having a credit rating of “A” (or the equivalent thereof) or better from either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc.;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition thereof at least “A” or the equivalent thereof by Standard & Poor’s Ratings Services, or “a2” or the equivalent thereof by Moody’s Investors Service, Inc., and having combined capital and surplus in excess of $500.0 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by Standard & Poor’s Ratings Services or “P-2” or the equivalent thereof by Moody’s Investors Service, Inc., or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in any case maturing within one year after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1) (A) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than Parent or one or more Permitted Holders, is or becomes the Beneficial Owner, directly or indirectly, of more than 50% of the total voting

142

power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause (1), such person or group shall be deemed to Beneficially Own any Voting Stock of the Company held by a parent entity, if such person or group Beneficially Owns, directly or indirectly, more than 50% of the total voting power of the Voting Stock of such parent entity) or (B) prior to the first underwritten public offering of Common Stock of the Company or any direct or indirect parent of the Company, the Permitted Holders cease to Beneficially Own, directly or indirectly, more than 35% of the Voting Stock of the Company;

(2) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors; or

(3) the 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 assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) other than a Permitted Holder or a Person controlled by a Permitted Holder;

(4) the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company; or

(5) the first day on which Parent ceases to own 100% of the outstanding Capital Stock of the Company (after having acquired such Capital Stock).

“Code” means the Internal Revenue Code of 1986, as amended.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person’s common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

“Consolidated Coverage Ratio” means as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDA of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness and the use of proceeds thereof as if such Indebtedness had been Incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such

143

computation, the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation, in each case, provided that such average daily balance shall take into account any repayment of Indebtedness under such facility as provided in clause (b)); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

(2) if, since the beginning of such period, the Company or any Restricted Subsidiary will have made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition, the Consolidated EBITDA for such period will be reduced by an amount equal to the Consolidated EBITDA (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDA (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) will have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or will have received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made hereunder, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition or contribution had occurred on the first day of such period; and

(4) if since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by

144

the Company or a Restricted Subsidiary during such period, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company (including pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

“Consolidated EBITDA” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Taxes of the Company and its Restricted Subsidiaries;

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangibles” and statement of Financial Accounting Standard No. 144 “Accounting for the Impairment or Disposal of Long Lived Assets”;

(5) other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) consolidated exploration expense of the Company and its Restricted Subsidiaries,

if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDA in any prior period).

145

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDA of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), 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 Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income, profits or capital of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense attributable to Capitalized Lease Obligations and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is Guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries;

(6) costs associated with Interest Rate Agreements (including amortization of fees); provided, however, that if Interest Rate Agreements result in net benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;

(8) all dividends paid or payable in cash, Cash Equivalents or Indebtedness or accrued during such period on any series of Disqualified Stock of the Company or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly-Owned Subsidiary; and

146

(9) the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company) in connection with Indebtedness Incurred by such plan or trust;

minus, to the extent included above, write-off of deferred financing costs (and interest) attributable to Dollar-Denominated Production Payments.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness,” the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (9) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness.”

“Consolidated Net Income” means, for any period, the aggregate net income (loss) of the Company and its consolidated Subsidiaries determined in accordance with GAAP and before any reduction in respect of preferred stock dividends of such Person; provided, however, that there will not be included in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

147

(4) any extraordinary or nonrecurring gains or losses, together with any related provision for taxes on such gains or losses and all related fees and expenses;

(5) the cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133);

(8) income or loss attributable to discontinued operations (including, without limitation, operations disposed of during such period whether or not such operations were classified as discontinued); and

(9) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards (other than non-cash compensation charges associated with the Phantom Unit Plan), provided that the proceeds resulting from any such grant will be excluded from clause (c)(ii) of the first paragraph of the covenant described under “—Limitations on Restricted Payments”.

Consolidated Net Income will be reduced by the amount of Permitted Payments to Parent paid during such period to the extent that the related taxes have not reduced Consolidated Net Income by at least such amount.

“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 Facility” means, with respect to the Company or any Subsidiary Guarantor, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement), indentures or commercial paper facilities 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 or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

148

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) at the option of the holder of the Capital Stock) or upon the happening of any event:

(1) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding; provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided, further, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that (i) the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “Change of control” and “Certain covenants—Limitation on sales of assets and Subsidiary stock” and (ii) such repurchase or redemption will be permitted solely to the extent also permitted in accordance with the provisions of the Indenture described under the caption “Certain covenants—Restricted Payments.”

The amount of any Disqualified Stock that does not have a fixed redemption, repayment or repurchase price will be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were redeemed, repaid or repurchased on any date on which the amount of such Disqualified Stock is to be determined pursuant to the Indenture; provided, however, that if such Disqualified Stock could not be required to be redeemed, repaid or repurchased at the time of such determination, the redemption, repayment or repurchase price will be the book value of such Disqualified Stock as reflected in the most recent financial statements of such Person.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Equity Offering” means (i) a public offering for cash by the Company of Capital Stock (other than Disqualified Stock) made pursuant to a registration statement, other than public offerings registered on Form S-4 or S-8 and (ii) a private offering for cash by the Company of its Capital Stock (other than Disqualified Stock); except that prior to the first underwritten public offering of the Company’s Common Stock, such private offering may only be made to non-Affiliates.

149

“Ethanol Subsidiary” means Oklahoma Ethanol L.L.C., an Oklahoma limited liability company, together with any successor entity, so long as such entity is engaged primarily in the production or sale of ethanol and its by-products including CO2.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business or any obligation to the extent it is payable only in Capital Stock of the Guarantor that is not Disqualified Stock. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

“holder” means a Person in whose name a Note is registered on the registrar’s books.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $500,000 and whose total revenues for the most recent 12-month period do not exceed $500,000; 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.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become directly or indirectly liable for, contingently or otherwise; provided, however, that any Indebtedness or Capital Stock

150

of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication, whether or not contingent):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable, to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such obligation is satisfied within 30 days of payment on the letter of credit);

(4) the principal component of all obligations of such Person (other than obligations payable solely in Capital Stock that is not Disqualified Stock) to pay the deferred and unpaid purchase price of property (except accrued expenses and trade payables and other accrued liabilities arising in the ordinary course of business that are not overdue by 90 days or more or are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto to the extent such obligations would appear as a liabilities upon the consolidated balance sheet of such Person in accordance with GAAP;

(5) Capitalized Lease Obligations of such Person to the extent such Capitalized Lease Obligations would appear as liabilities on the consolidated balance sheet of such Person in accordance with GAAP;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the fair market value of such asset at such date of determination (as determined in the good faith by the Board of Directors) and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time);

151

provided, however, that any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, shall not constitute “Indebtedness.”

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

Notwithstanding the preceding, “Indebtedness” shall not include:

(1) Production Payments and Reserve Sales;

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property;

(3) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided, that such Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries Incurred without violation of the Indenture;

(4) any obligation arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, Guarantees, adjustment of purchase price, holdbacks, contingency payment obligations or similar obligations (other than Guarantees of Indebtedness), in each case, Incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary, provided that such Indebtedness is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(5) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business, provided, however, that such Indebtedness is extinguished within five business days of Incurrence;

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

152

(7) all contracts and other obligations, agreements instruments or arrangements described in clauses (20), (21), (22), (29)(a) or (30) of the definition of “Permitted Liens.”

In addition, “Indebtedness” of any Person shall include Indebtedness described in the first paragraph of this definition of “Indebtedness” that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture or otherwise liable for all or a portion of the Joint Venture’s liabilities (a “General Partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit and advances or extensions of credit to customers in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments (excluding any interest in a crude oil or natural gas leasehold to the extent constituting a security under applicable law) issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;

(2) endorsements of negotiable instruments and documents in the ordinary course of business; and

(3) an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Common Stock of the Company.

153

The amount of any Investment shall not be adjusted for increases or decreases in value, write-ups, write-downs or write-offs with respect to such Investment.

For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “Certain covenants—Limitation on Restricted Payments,”

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the fair market value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets of such Subsidiary (as conclusively determined by the Board of Directors of the Company in good faith) at the time that such Subsidiary is so re-designated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

“Issue Date” means the first date on which the Notes are issued under the indenture.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority 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; provided that in no event shall an operating lease be deemed to constitute a Lien.

“Minority Interest” means the percentage interest represented by any shares of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

154

(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock or any contribution to equity capital, means the cash proceeds of such issuance, sale or contribution net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance, sale or contribution and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof 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 Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

“Officers’ Certificate” means a certificate signed by an Officer of the Company.

155

“Oil and Gas Business” means: (1) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, liquid natural gas and other hydrocarbon and mineral properties or products produced in association with any of the foregoing; (2) the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other hydrocarbons and minerals obtained from unrelated Persons; (3) any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other hydrocarbons and minerals produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participates; (4) any business relating to oil field sales and service; and (5) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (4) of this definition (including, without limitation, the acquisition, development and operation of CO2 producing properties, the acquisition or construction and operation of CO2 pipelines and transportation or sales of CO2, and the ownership and operation of ethanol plants, a by-product of which is the production of CO2, as related to the activities described in the foregoing clauses (1) through (2)).

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“Parent” means any entity that acquires 100% of the outstanding Capital Stock of the Company in a transaction in which the Beneficial Owners of the Company immediately prior to such transaction are Beneficial Owners in the same proportion of the Company immediately after such transaction.

“Pari Passu Indebtedness” means Indebtedness that ranks equally in right of payment to the Notes.

“Permitted Business Investment” means any Investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil, natural gas or other hydrocarbons and minerals through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1) ownership interests in oil, natural gas, other hydrocarbons and minerals properties, liquid natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties (including Unrestricted Subsidiaries); and

156

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

“Permitted Holders” means:

(1) Mark A. Fischer, Charles A. Fischer, Jr., Mark A. Fischer 1994 Trust and Susan L. Fischer 1994 Trust;

(2) any immediate family member (in the case of an individual) of any Person referred to in clause (1); or

(3) any trust, corporation, partnership or other entity, the beneficiaries, stockholders, partners, owners or Persons Beneficially Owning a 50% or more controlling interest of which consist of any one or more Persons referred to in clause (1) or (2).

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company, a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) another Person whose primary business is the Oil and Gas Business if as a result of such Investment such other Person becomes a Restricted Subsidiary or is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary and, in each case, any Investment held by such Person; provided, that such Investment was not acquired by such Person in contemplation of such acquisition, merger, consolidation or transfer;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, commission, travel, relocation and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary;

(7) Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments;

(8) Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with the covenant described under “Certain covenants—Limitation on sales of assets and Subsidiary stock”;

(9) Investments in existence on the Issue Date;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with “Certain covenants—Limitation on Indebtedness and Preferred Stock”;

157

(11) Guarantees issued in accordance with the covenant described under “Certain covenants—Limitations on Indebtedness”;

(12) any Asset Swap or acquisition of Additional Assets made in accordance with the covenant described under “Certain covenants—Limitation on sales of assets and Subsidiary stock”;

(13) Investments in the Ethanol Subsidiary having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (13) that are at the time outstanding, not to exceed $35.0 million (with the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);

(14) Permitted Business Investments;

(15) any Person where such Investment was acquired by the Company or any of its Restricted Subsidiaries (a) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable or (b) as a result of a foreclosure by the Company or any of its Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

(16) any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;

(17) Guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses or concessions related to the Oil and Gas Business;

(18) acquisitions of assets, Equity Interests or other securities by the Company for consideration consisting of common equity securities of the Company;

(19) Investments in the Notes; and

(20) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (20), in an aggregate amount at the time of such Investment not to exceed $25.0 million outstanding at any one time (with the fair market value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value).

“Permitted Liens” means, with respect to any Person:

(1) Liens securing Indebtedness and other obligations under, and related Hedging Obligations and Liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under, any Credit Facility permitted to be Incurred under the Indenture under the provisions described in clause (1) of the second paragraph under “Certain covenants—Limitation on Indebtedness and Preferred Stock”;

158

(2) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws, social security or old age pension laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits (which may be secured by a Lien) to secure public or statutory obligations of such Person including letters of credit and bank guarantees required or requested by the United States, any State thereof or any foreign government or any subdivision, department, agency, organization or instrumentality of any of the foregoing in connection with any contract or statute (including lessee or operator obligations under statutes, governmental regulations, contracts or instruments related to the ownership, exploration and production of oil, natural gas, other hydrocarbons and minerals on State, Federal or foreign lands or waters), or deposits of cash or United States government bonds to secure indemnity performance, surety or appeal bonds or other similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) statutory and contractual Liens of landlords and Liens imposed by law, including carriers’, warehousemen’s, mechanics’ materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges or claims not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings; provided that appropriate reserves, if any, required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6) survey exceptions, encumbrances, ground leases, 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, building codes or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of the assets of such Person and its Restricted Subsidiaries, taken as a whole, or materially impair their use in the operation of the business of such Person;

(7) Liens securing Hedging Obligations so long as the related Indebtedness is, and is permitted to be under the Indenture, secured by a Lien on the same property securing such Hedging Obligation;

(8) leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9) prejudgment Liens and judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been

159

duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business; provided that;

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture; and

(b) such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) Liens existing on the Issue Date;

(14) Liens on property or shares of Capital Stock of a Person at the time such Person becomes a Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

(15) Liens on property at the time the Company or any of its Subsidiaries acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any of its Subsidiaries; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

(16) Liens securing Indebtedness or other obligations of a Subsidiary owing to the Company or a Wholly-Owned Subsidiary;

(17) Liens securing the Notes, Subsidiary Guarantees and other obligations under the Indenture;

160

(18) Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(19) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20) Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;

(21) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business;

(22) Liens on pipelines or pipeline facilities that arise by operation of law;

(23) Liens securing Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount outstanding at any one time, added together with all other Indebtedness secured by Liens Incurred pursuant to this clause (23), not to exceed $10.0 million;

(24) Liens in favor of the Company or any Subsidiary Guarantor;

(25) deposits made in the ordinary course of business to secure liability to insurance carriers;

(26) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods in the ordinary course of business;

(27) Liens deemed to exist in connection with Investments in repurchase agreements permitted under “Certain covenants—Limitation on Indebtedness and Preferred Stock”; provided that such Liens do not extend to any assets other than those that are the subject of such repurchase agreement;

(28) Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(29) any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics’ liens, tax liens,

161

and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b);

(30) Liens (other than Liens securing Indebtedness) on, or related to, 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;

(31) Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(32) Liens arising under the Indenture in favor of the Trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the Indenture, provided, however, that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of such Indebtedness;

(33) Liens arising from the deposit of funds or securities in trust for the purpose of decreasing or defeasing Indebtedness so long as such deposit of funds or securities and such decreasing or defeasing of Indebtedness are permitted under the covenant described under “—Certain covenants—Limitation on Restricted Payments”;

(34) Liens in favor of collecting or payer banks having a right of setoff, revocation, or charge back with respect to money or instruments of the Company or any Subsidiary of the Company on deposit with or in possession of such bank; and

(35) Liens on the Capital Stock of the Ethanol Subsidiary held by the Company or its Restricted Subsidiaries in favor of any lender to the Ethanol Subsidiary.

In each case set forth above, notwithstanding any stated limitation on the assets that may be subject to such Lien, a Permitted Lien on a specified asset or group or type of assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof (including dividends, distributions and increases in respect thereof).

“Permitted Payments to Parent” means, 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 (a) 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 (b) 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.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

162

“Phantom Unit Plan” means the Company’s phantom unit plan as in effect on the Issue Date, as it may be amended or modified from time to time.

“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and 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 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 the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay, extend, prepay, redeem or retire (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances” and “refinanced” shall have correlative meanings) any Indebtedness (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary, but excluding Indebtedness of a Subsidiary that is not a Restricted Subsidiary that refinances Indebtedness of the Company or a Restricted Subsidiary), including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a) if the Stated Maturity of the Indebtedness being Refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

163

(4) if the Indebtedness being Refinanced is subordinated in right of payment to the Notes or the Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being Refinanced.

“Registration Rights Agreement” means that certain registration rights agreement dated as of the date of the Indenture by and among the Company, the Subsidiary Guarantors and the initial purchasers set forth therein.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“SEC” means the United States Securities and Exchange Commission.

“Senior Secured Credit Agreement” means the Sixth Restated Credit Agreement dated as of June 22, 2005 among the Company, as Parent Guarantor, the Subsidiaries of the Company parties thereto as Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders parties thereto from time to time, as amended by the First Amendment to Sixth Restated Credit Agreement, dated September 30, 2005, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain covenants—Limitation on Indebtedness and Preferred Stock” above).

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC, as in effect on the Issue Date.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company (whether outstanding on the Issue Date or thereafter Incurred) that is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof

164

(or Persons performing similar functions) or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary (other than in this definition) will refer to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any Guarantee of payment of the Notes and exchange notes issued in a registered exchange offer pursuant to the Registration Rights Agreement by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

“Subsidiary Guarantor” means Triumph Tools & Supply, L.L.C., Chaparral Oil, L.L.C., Chaparral Texas, L.P., Chaparral Real Estate, L.L.C., Chaparral Resources, L.L.C., Chaparral CO2, L.L.C., Noram Petroleum, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C. and CEI Bristol Acquisition, L.P., and any Restricted Subsidiary created or acquired by the Company after the Issue Date (other than a Foreign Subsidiary) that Incurs any Indebtedness.

“Unrestricted Subsidiary” means:

(1) any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company in such Subsidiary complies with “Certain covenants—Limitation on restricted payments”;

(4) such Subsidiary 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 Capital Stock of such Person; 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

(5) on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any

165

Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

In addition, without further designation, the Ethanol Subsidiary will be an Unrestricted Subsidiary.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the covenant described under “Certain covenants—Limitation on Indebtedness and Preferred Stock” on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“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 an entity means all classes of Capital Stock of such entity then outstanding and normally entitled to vote in the election of members of such entity’s Board of Directors.

“Wholly-Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly-Owned Subsidiary.

166

Global securities; book-entry system

The global securities

The notes will initially be represented by one or more permanent global notes in definitive, fully registered book-entry form (the “global securities”) which will be registered in the name of Cede & Co., as nominee of DTC, or such other name as may be requested by an authorized representative of DTC. The global notes will be deposited with the Trustee as custodian for DTC and may not be transferred except as a whole by DTC to a nominee of DTC or by a nominee of DTC to DTC or another nominee of DTC or by DTC or any nominee to a successor of DTC or a nominee of such successor.

We expect that pursuant to procedures established by DTC (a) upon deposit of the global securities, DTC or its custodian will credit on its internal system portions of the global securities which will contain the corresponding respective amount of the global securities to the respective accounts of persons who have accounts with such depositary and (b) ownership of the notes will be shown on, and the transfer of ownership thereof will be affected only through, records maintained by DTC or its nominee (with respect to interests of participants (as defined below)) and the records of participants (with respect to interests of persons other than participants). Such accounts initially will be designated by or on behalf of the initial purchasers and ownership of beneficial interests in the global securities will be limited to persons who have accounts with DTC (the “participants”) or persons who hold interests through participants. Noteholders may hold their interests in a global security directly through DTC if they are participants in such system, or indirectly through organizations which are participants in such system.

So long as DTC or its nominee is the registered owner or holder of any of the notes, DTC or such nominee will be considered the sole owner or holder of such notes represented by such global securities for all purposes under the indenture and under the notes represented thereby. No beneficial owner of an interest in the global securities will be able to transfer such interest except in accordance with the applicable procedures of DTC.

Certain book-entry procedures for the global securities

The operations and procedures of DTC is solely within the control of DTC and are subject to change by them from time to time. Investors are urged to contact the DTC or its participants directly to discuss these matters.

DTC has advised us that it is:

• 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 Banking Law;

• a member of the Federal Reserve System;

• a “clearing corporation” within the meaning of the New York Uniform Commercial Code, as amended; and

• a “clearing agency” registered pursuant to Section 17A of the Securities Exchange Act of 1934.

DTC was created to hold securities for its participants (collectively, the “participants”) and to facilitate the clearance and settlement of securities transactions, such as transfers and pledges,

167

between participants through electronic book-entry changes to the accounts of its participants, thereby eliminating the need for physical transfer and delivery of certificates. DTC’s participants include securities brokers and dealers (including the initial purchasers), banks and trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation, which is owned by a number of direct participants of DTC and by the New York Stock Exchange, Inc., the American Stock Exchange, LLC and the National Association of Securities Dealers, Inc. Indirect access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies (collectively, the “indirect participants”) that clear through or maintain a custodial relationship with a participant, either directly or indirectly. Investors who are not participants may beneficially own securities held by or on behalf of DTC only through participants or indirect participants. The rules applicable to DTC and its participants are on file with the SEC.

The laws of some jurisdictions may require that some purchasers of securities take physical delivery of those securities in definitive form. Accordingly, the ability to transfer beneficial interests in notes represented by a global security to those persons may be limited. In addition, because DTC can act only on behalf of its participants, who in turn act on behalf of persons who hold interests through participants, the ability of a person holding a beneficial interest in a global security to pledge or transfer that interest to persons or entities that do not participate in DTC’s system, or to otherwise take actions in respect of that interest, may be affected by the lack of a physical security in respect of that interest.

So long as DTC or its nominee is the registered owner of a global security, DTC or that nominee, as the case may be, will be considered the sole legal owner or holder of the notes represented by that global security for all purposes of the notes and the indenture. Except as provided below, owners of beneficial interests in a global security will not be entitled to have the notes represented by that global security registered in their names, will not receive or be entitled to receive physical delivery of certificated securities, and will not be considered the owners or holders of the notes represented by that beneficial interest under the indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the Trustee. To facilitate subsequent transfers, all global securities that are deposited with, or on behalf of, DTC will be registered in the name of DTC’s nominee, Cede & Co. The deposit of global securities with, or on behalf of, DTC and their registration in the name of Cede & Co. effect no change in beneficial ownership. We understand that DTC has no knowledge of the actual beneficial owners of the securities. Accordingly, each holder owning a beneficial interest in a global security must rely on the procedures of DTC and, if that holder is not a participant or an indirect participant, on the procedures of the participant through which that holder owns its interest, to exercise any rights of a holder of notes under the indenture or that global security. We understand that under existing industry practice, in the event that we request any action of holders of notes, or a holder that is an owner of a beneficial interest in a global security desires to take any action that DTC, as the holder of that global security, is entitled to take, DTC would authorize the participants to take that action and the participants would authorize holders owning through those participants to take that action or would otherwise act upon the instruction of those holders.

Conveyance of notices and other communications by DTC to its direct participants, by its direct participants to indirect participants and by its direct and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time.

168

Neither DTC nor Cede & Co. will consent or vote with respect to the global securities unless authorized by a direct participant under DTC’s procedures. Under its usual procedures, DTC will mail an omnibus proxy to us as soon as possible after the applicable record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants of DTC to whose accounts the securities are credited on the applicable record date, which are identified in a listing attached to the omnibus proxy.

Neither we nor the Trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial interests in the global securities by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those beneficial interests.

Payments with respect to the principal of and premium, if any, liquidated damages, if any, and interest on a global security will be payable by the Trustee to or at the direction of DTC or its nominee in its capacity as the registered holder of the global security under the Indenture. Under the terms of the Indenture, we and the Trustee may treat the persons in whose names the notes, including the global securities, are registered as the owners thereof for the purpose of receiving payment thereon and for any and all other purposes whatsoever. Accordingly, neither we nor the Trustee has or will have any responsibility or liability for the payment of those amounts to owners of beneficial interests in a global security. It is our understanding that DTC’s practice is to credit the direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from us or the Paying Agent on the applicable payment date in accordance with their respective holdings shown on DTC’s records. Payments by the participants and the indirect participants to the owners of beneficial interests in a global security will be governed by standing instructions and customary industry practice and will be the responsibility of the participants and indirect participants and not of DTC, us or the Trustee, subject to statutory or regulatory requirements in effect at the time.

Transfers between participants in DTC will be effected in accordance with DTC’s procedures, and, except for trades involving only the Euroclear System as operated by Euroclear Bank S.A./N.V., or Euroclear, or Clearstream Banking, S.A. of Luxembourg, or Clearstream Luxembourg, such transfers will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream Luxembourg will be effected in the ordinary way in accordance with their respective rules and operating procedures.

Cross-market transfers between the participants in DTC, on the one hand, and Euroclear or Clearstream Luxembourg participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream Luxembourg, as the case may be, by its respective depositary; however, those cross-market transactions will require delivery of instructions to Euroclear or Clearstream Luxembourg, as the case may be, by the counterparty in that system in accordance with the rules and procedures and within the established deadlines (Brussels time) of that system. Euroclear or Clearstream Luxembourg, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global securities in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream Luxembourg participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream Luxembourg.

169

Because of time zone differences, the securities account of a Euroclear or Clearstream Luxembourg participant purchasing an interest in a global security from a participant in DTC will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream Luxembourg participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream Luxembourg) immediately following the settlement date of DTC. Cash received in Euroclear or Clearstream Luxembourg as a result of sales of interests in a global security by or through a Euroclear or Clearstream Luxembourg participant to a participant in DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream Luxembourg cash account only as of the business day for Euroclear or Clearstream Luxembourg following DTC’s settlement date.

Although DTC has agreed to the foregoing procedures to facilitate transfers of interests in the global securities among participants in DTC, it is under no obligation to perform or to continue to perform those procedures, and those procedures may be discontinued at any time. Neither we nor the Trustee will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Certificated notes

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 90 days;

• DTC ceases to be registered as a clearing agency under the Exchange Act and a successor depositary is not appointed within 90 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.

We have provided the foregoing information with respect to DTC to the financial community for information purposes only. Although we obtained the information in this section and elsewhere in this prospectus concerning DTC and its book-entry system from sources that we believe are reliable, we take no responsibility for the accuracy of such information.

170

Material United States federal income tax

considerations

In the opinion of Andrews Kurth LLP, our legal counsel, the following are the material U.S. federal income tax considerations relevant to the exchange of new notes for old notes pursuant to the exchange offer. The discussion does not purport to be a complete analysis of all potential tax effects and 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. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations.

The exchange of new notes for old notes pursuant to the exchange offer will not be a taxable exchange for U.S. federal income tax purposes. A holder will not recognize any taxable gain or loss as a result of the exchange and will have the same tax basis and holding period in the new notes as the holder had in the old notes immediately before the exchange.

171

Plan of distribution

Each broker–dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker–dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market–making activities or other trading activities. We have agreed that, for 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker–dealer for use in connection with any such resale. In addition, until October 17, 2006, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of new notes by broker–dealers. New notes received by broker–dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over–the–counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker–dealer or the purchasers of any such new notes. Any broker–dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The enclosed letter of transmittal states that, by acknowledging that it will deliver and be delivering a prospectus, a broker–dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker–dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker–dealers) against certain liabilities, including liabilities under the Securities Act.

Following completion of the exchange offer, we may, in our sole discretion, commence one or more additional exchange offers to holders of old notes who did not exchange their old notes for new notes in the exchange offer on terms which may differ from those contained in this prospectus and the enclosed letter of transmittal. This prospectus, as it may be amended or supplemented from time to time, may be used by us in connection with any additional exchange offers. These additional exchange offers may take place from time to time until all outstanding old notes have been exchanged for new notes, subject to the terms and conditions in the prospectus and letter of transmittal distributed by us in connection with these additional exchange offers.

172

Legal matters

The validity of the new notes and certain other matters will be passed upon for us by Andrews Kurth LLP, Houston, Texas.

Experts

The consolidated financial statements of Chaparral Energy Inc. and subsidiaries as of December 31, 2004 and 2005 and for each of the three years in the period ended December 31, 2005 and the financial statements of CEI Bristol Acquisition, L.P. as of December 31, 2003 and 2004 and for each of the three years in the period ended December 31, 2004, included in this prospectus and registration statement, have been audited by Grant Thornton LLP, independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

Independent petroleum engineers

Certain estimates of our net oil and natural gas reserves and related information as of December 31, 2003 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. Certain estimates of our net proved oil and natural gas reserves and the net proved oil and natural gas reserves of CEI Bristol as of December 31, 2004 and 2005 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc. All such information has been so included on the authority of such firms as experts regarding the matters contained in their reports.

Where you can find more information

We have filed with the SEC a registration statement on Form S-4, including exhibits and schedules, under the Securities Act with respect to the offer to exchange our senior notes. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules that are part of the registration statement. For further information about us and the exchange offer, you should refer to the registration statement. Any statements made in this prospectus as to the contents of any contract, agreement or other document are not necessarily complete. With respect to each such contract, agreement or other document filed as an exhibit to the registration statement, you should refer to the exhibit for a more complete description of the matter involved, and each statement in this prospectus shall be deemed qualified in its entirety by this reference.

You may read, without charge, and copy, at prescribed rates, all or any portion of the registration statement or any reports, statements or other information in the files at the public reference facilities of the SEC’s principal office at 100 F Street NE, Washington, D.C., 20549. You can request copies of these documents upon payment of a duplicating fee by writing to the SEC. You may call the SEC at 1-800-SEC-0330 for further information on the operation of its public reference rooms. Our filings, including the registration statement, will also be available to you on the Internet web site maintained by the SEC at http://www.sec.gov.

Following the completion of this exchange offer or the initial public offering of our common stock, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities

173

maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at http://www.chaparralenergy.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Chaparral Energy, Inc., Attention: Chief Financial Officer, 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114, (405) 478-8770.

We intend to furnish or make available to our stockholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

174

Glossary of terms

The terms defined in this section are used throughout this prospectus:

Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
Bcf	One billion cubic feet of natural gas.
Bcfe	One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Basin	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Fully developed finding, development and acquisition cost (FD&A)	Total costs incurred plus the increase in future development costs divided by total proved reserve acquisitions, extensions and discoveries and revisions.
Henry Hub spot price	The price of natural gas, in dollars per MMbtu, being traded at the Henry Hub in Louisiana in transactions for next-day delivery, measured downstream from the wellhead after the natural gas liquids have been removed and a transportation cost has been incurred.
Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Infill wells	Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.
MBbl	One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf	One thousand cubic feet of natural gas.
Mcfe	One thousand cubic feet of natural gas equivalents.
MMBbl	One million barrels of crude oil, condensate or natural gas liquids.
MMBtu	One million British thermal units.

A-1

MMcf	One million cubic feet of natural gas.
MMcfe	One million cubic feet of natural gas equivalents.
NYMEX	The New York Mercantile Exchange.
Net acres	The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
Net working interest	A working interest owner’s gross working interest in production, less the related royalty, overriding royalty, production payment, and net profits interests.
PDP	Proved developed producing.
PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.
Primary recovery	The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.
Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves	The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Sand	A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.
Secondary recovery	The recovery of oil and gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

A-2

Seismic survey	Also known as a seismograph survey, is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
Tertiary recovery	The use of any improved recovery method, including injection of CO2, to remove additional oil after secondary recovery. Compare primary recovery, secondary recovery.
Unit	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
WTI Cushing spot price	The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.
Waterflood	The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
Wellbore	The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
Working interest	The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Zone	A layer of rock which has distinct characteristics that differ from nearby rock.

A-3

Index to financial statements

	Page
Chaparral Energy, Inc. historical consolidated financial statements:
Report of independent registered public accounting firm	F1-1
Consolidated balance sheets as of December 31, 2004 and 2005 and March 31, 2006 (unaudited)	F1-2
Consolidated statements of income for the years ended December 31, 2003, 2004 and 2005 and the three months ended March 31, 2005 and 2006 (unaudited)	F1-3
Consolidated statements of members’/stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2003, 2004 and 2005 and the three months ended March 31, 2006 (unaudited)	F1-4
Consolidated statements of cash flows for the years ended December 31, 2003, 2004 and 2005 and the three months ended March 31, 2005 and 2006 (unaudited)	F1-5
Notes to consolidated financial statements	F1-7
CEI Bristol historical financial statements:
Report of independent registered public accounting firm	F2-1
Balance sheets as of December 31, 2003 and 2004 and September 30, 2005 (unaudited)	F2-2
Statements of operations for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F2-3
Statement of partners’ capital for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2005 (unaudited)	F2-4
Statements of cash flows for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F2-5
Notes to financial statements	F2-7

F-1

Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and Subsidiaries as of December 31, 2004 and 2005, and the related consolidated statements of income, members’/stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2005. 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. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and Subsidiaries as of December 31, 2004 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

/s/    GRANT THORNTON LLP

Oklahoma City, Oklahoma

June 1, 2006

F1-1

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	December 31,						March 31,
(dollars in thousands, except share data)	2004			2005			2006 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	13,842		$	1,598		$	8,476
Accounts receivable, net		26,357			42,431			38,655
Accounts receivable from related party		1,444			—			—
Inventories		3,596			6,788			7,060
Deferred income taxes		5,772			23,831			16,575
Prepaid expenses		1,488			1,591			1,213
Hedge instruments		—			1,016			3,818
Total current assets		52,499			77,255			75,797
Property and equipment—at cost, net		19,920			22,428			23,390
Oil & gas properties, using the full cost method:
Proved		274,466			600,185			643,230
Unproved		4,982			10,150			12,721
Accumulated depletion and depreciation		(47,683	)		(74,799	)		(84,772	)
Total oil & gas properties		231,765			535,536			571,179
Other assets		4,643			12,160			12,110
	$	308,827		$	647,379		$	682,476
Liabilities and members'/stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities	$	27,422		$	44,183		$	44,215
Revenue distribution payable		13,794			8,858			13,179
Current maturities of long-term debt and capital leases		2,159			3,126			3,398
Short-term hedge instruments		13,810			63,125			41,452
Total current liabilities		57,185			119,292			102,244
Long-term debt and capital leases, less current maturities		174,463			118,418			143,627
8 1/2% Senior Notes, due 2015		—			325,000			325,000
Hedge instruments		7,425			32,001			23,283
Deferred compensation		120			645			755
Asset retirement obligations		10,062			15,450			15,960
Deferred income taxes		22,986			26,406			35,597
Commitments and contingencies (note 12)
Members'/stockholders' equity:
Members' units/common stock, 50,000,000 units issued and outstanding as of December 31, 2004; common stock, $.01 par value—5,000 shares authorized; 1,000 shares issued and outstanding as of December 31, 2005 and March 31, 2006		1			1			1
Undistributed/retained earnings		48,692			58,133			68,155
Accumulated other comprehensive loss, net of taxes		(12,107	)		(47,967	)		(32,146	)
		36,586			10,167			36,010
	$	308,827		$	647,379		$	682,476

The accompanying notes are an integral part of these statements.

F1-2

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of income

	Year Ended December 31,									Three months ended March 31,
(dollars in thousands)	2003			2004			2005			2005 (unaudited)			2006 (unaudited)
Revenues:
Oil and gas sales	$	74,186		$	113,546		$	201,410		$	36,149		$	61,295
Loss from oil and gas hedging activities		(12,220	)		(21,350	)		(68,324	)		(8,839	)		(1,153	)
Total revenues		61,966			92,196			133,086			27,310			60,142
Costs and expenses:
Lease operating		19,520			26,928			42,147			8,636			15,133
Production tax		4,840			8,272			14,626			2,651			4,658
Depreciation, depletion and amortization		10,376			17,533			31,423			6,251			11,053
General and administrative		4,946			5,985			9,808			2,300			3,405
Total costs and expenses		39,682			58,718			98,004			19,838			34,249
Operating income		22,284			33,478			35,082			7,472			25,893
Non-operating income (expense):
Interest expense		(4,116	)		(6,162	)		(15,588	)		(2,345	)		(9,165	)
Other income		208			279			665			173			104
Net non-operating expense		(3,908	)		(5,883	)		(14,923	)		(2,172	)		(9,061	)
Income from before income taxes and accounting change		18,376			27,595			20,159			5,300			16,832
Income tax expense		6,932			9,880			7,309			2,037			6,460
Income before accounting change		11,444			17,715			12,850			3,263			10,372
Cumulative effect of change in accounting principle, less applicable income tax benefit of $537		(887	)		—			—			—			—
Net income	$	10,557		$	17,715		$	12,850		$	3,263		$	10,372

The accompanying notes are an integral part of these statements.

F1-3

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of members'/

stockholders' equity and comprehensive

income (loss)

	Members' units/ Common Stock				Undistributed/ Retained earnings			Accumulated other comprehensive income (loss)			Total
(dollars in thousands)	Units/Shares		Amount
Balance at January 1, 2003	50,000,000		$	1	$	20,420		$	(3,733	)	$	16,688
Net income	—			—		10,557			—			10,557
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $5,193	—			—		—			(8,530	)		(8,530	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $4,437	—			—		—			7,363			7,363
Total comprehensive income												9,390
Balance at December 31, 2003	50,000,000			1		30,977			(4,900	)		26,078
Net income	—			—		17,715			—			17,715
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $12,766	—			—		—			(20,152	)		(20,152	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $7,801	—			—		—			12,945			12,945
Total comprehensive income												10,508
Balance at December 31, 2004	50,000,000			1		48,692			(12,107	)		36,586
Conversion from LLC to C Corporation	(49,999,000	)		—		—			—			—
Distributions to members	—			—		(3,409	)		—			(3,409	)
Net income	—			—		12,850			—			12,850
Other comprehensive loss, net
Unrealized loss on hedges, net of taxes of $42,970	—			—		—			(68,749	)		(68,749	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $20,694	—			—		—			32,889			32,889
Total comprehensive loss												(23,010	)
Balance at December 31, 2005	1,000			1		58,133			(47,967	)		10,167
Distributions to members	—			—		(350	)		—			(350	)
Net income	—			—		10,372			—			10,372
Other comprehensive income, net
Unrealized gain on hedges, net of taxes of $6,681	—			—		—			10,576			10,576
Reclassification adjustment for hedge losses included in net income, net of taxes of $3,300	—			—		—			5,245			5,245
Total comprehensive income												26,193
Balance at March 31, 2006	1,000		$	1	$	68,155		$	(32,146	)	$	36,010

The accompanying notes are an integral part of this statement.

F1-4

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Year Ended December 31,									Three months ended March 31,
(dollars in thousands)	2003			2004			2005			2005 (unaudited)			2006 (unaudited)
Cash flows from operating activities
Net income	$	10,557		$	17,715		$	12,850		$	3,263		$	10,372
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		10,376			17,533			31,423			6,251			11,053
Cumulative effect of accounting change		1,424			—			—			—			—
Deferred income taxes		6,959			9,693			7,637			2,033			6,467
Unrealized (gain) loss on ineffective portion of hedges		420			604			14,740			4,367			(7,392	)
(Gain) loss on sale of assets		23			97			(231	)		(119	)		20
Partnership income		(45	)		(173	)		(26	)		—			—
Accrued interest expense added to principal		99			27			—			—			—
Amortization of bond issue costs		—			—			48			—			142
Bad debt expense		359			248			140			36			71
Change in assets & liabilities
(Increase) Decrease in accounts receivable		(15,184	)		278			(7,979	)		(1,952	)		3,705
(Increase) Decrease in inventories		(344	)		(1,402	)		(2,961	)		(363	)		(272	)
(Increase) Decrease in prepaid expenses and other assets		(14	)		(834	)		(270	)		19			410
Increase (Decrease) in accounts payable and accrued liabilities		8,813			5,942			14,151			6,354			13
Increase (Decrease) in revenue distribution payable		9,098			1			(4,936	)		(1,628	)		4,321
Increase in deferred compensation		—			120			525			75			110
Net cash provided by operating activities		32,541			49,849			65,111			18,336			29,020
Cash flows from investing activities
Partnership investment		(40	)		(72	)		(33	)		—			—
Partnership distribution		53			152			63			35			—
Purchase of property and equipment and oil and gas properties		(56,652	)		(97,926	)		(179,937	)		(34,444	)		(50,769	)
Acquisition of a business, net of cash acquired		—			—			(113,622	)		—			—
Payment on non-hedge derivative transactions assumed in acquisition of a business		—			—			(42,108	)		—			—
Proceeds from dispositions of property and equipment and oil and gas properties		1,426			2,726			1,202			260			3,725
Net cash used in investing activities		(55,213	)		(95,120	)		(334,435	)		(34,149	)		(47,044	)
Cash flows from financing activities
Proceeds from long-term debt		28,491			58,358			122,676			12,806			26,172
Repayment of long-term debt and acquisition financing		(583	)		(2,431	)		(309,383	)		(351	)		(650	)
Proceeds from acquisition financing		—			—			132,000			—			—
Proceeds from senior notes		—			—			325,000			—			—
Principal payments under capital lease obligations		(744	)		(807	)		(442	)		(192	)		(40	)
Repayments of notes payable to members		(1,018	)		(1,059	)		—			—			—
Distributions to members		—			—			(3,409	)		(2,350	)		(350	)
Fees paid related to financing activities		—			—			(9,195	)		—			27
Fees paid related to IPO activities		—			—			(167	)		—			(257	)
Net cash provided by financing activities		26,146			54,061			257,080			9,913			24,902
Net increase (decrease) in cash and cash equivalents		3,474			8,790			(12,244	)		(5,900	)		6,878
Cash and cash equivalents at beginning of year		1,578			5,052			13,842			13,842			1,598
Cash and cash equivalents at end of year	$	5,052		$	13,842		$	1,598		$	7,942		$	8,476

The accompanying notes are an integral part of these statements.

F1-5

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(continued)

	Year Ended December 31,							Three Months Ended March 31,
(dollars in thousands)	2003		2004		2005			2005		2006
Supplemental cash flow information
Cash paid (received) during the year for:
Interest, net of capitalized interest	$	3,898	$	5,524	$	12,590		$	2,113	$	2,062
Income taxes		—		17		(328	)		4		(7	)

Supplemental disclosure of noncash investing and financing activities

During the year ended December 31, 2003, the Company entered into capital lease obligations of $330 for the purchase of lease and well equipment. During the year ended December 31, 2004, the Company entered into capital leases for the purchase of machinery and equipment of $82 and purchased two licenses for seismic data by incurring long-term obligations of $4,096. During the year ended December 31, 2005, the Company entered into capital lease obligations of $70 for the purchase of machinery and equipment.

Effective on January 1, 2003, the Company recorded the cumulative effect of SFAS No. 143 for asset retirement obligations, as follows:

Increase in oil and gas properties	$	4,437
Increase in asset retirement obligations		(5,861	)
Cumulative effect of accounting change	$	(1,424	)

During the year ended December 31, 2004 and December 31, 2005, the Company recorded an asset and related liability of $2,115 and $4,680, respectively associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties. (see “Asset Retirement Obligations” section of Note 1). During the three months ended March 31, 2005 and 2006, the Company recorded an asset and related liability of $212 and $235, respectively.

The accompanying notes are an integral part of these statements.

F1-6

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and its majority owned subsidiaries, formerly Chaparral, L.L.C. and Subsidiaries, (collectively, the “Company”) is involved in the acquisition, exploration, development, production and operation of oil and gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas and Wyoming.

Chaparral Energy, Inc. was incorporated in the state of Delaware on September 14, 2005 as a wholly owned subsidiary of Chaparral, L.L.C. Chaparral, L.L.C. was then merged with and into Chaparral Energy, Inc. effective September 16, 2005, with Chaparral Energy, Inc. surviving the merger. At the effective time of the merger, all shares of capital stock of Chaparral Energy, Inc. issued and outstanding prior to the merger were cancelled and all units of Chaparral, L.L.C. issued and outstanding prior to the merger were converted to 1,000 shares of the surviving entity, Chaparral Energy, Inc.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Interim financial statements

The financial information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three month period ended March 31, 2006 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2006.

Principles of Consolidation

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its majority owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, requires management to make estimates. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

F1-7

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Cash and Cash Equivalents

The Company maintains cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. At December 31, 2004, the Company had cash and cash equivalents of $11,654 at one financial institution, from which the Company also has significant borrowings.

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Accounts Receivable

The Company has receivables from joint interest owners and oil and gas purchasers which are generally uncollateralized. The Company generally reviews these parties for credit worthiness and general financial condition. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Accounts receivable past due 90 days or more and still accruing interest at December 31, 2004 and 2005 were $1,237 and $694, respectively. The Company determines its allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and gas properties operated by the Company and the owner’s ability to pay its obligation, among other things.

The Company writes off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2003, 2004, and 2005 was $359, $248, and $140, respectively. Interest accrues beginning on the day after the due date of the receivable. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against current interest income. Accounts receivable consisted of the following at December 31:

	2004			2005
Joint interests	$	11,645		$	14,682
Accrued oil and gas sales		13,651			27,075
Other		1,261			912
Allowance for doubtful accounts		(200	)		(238	)
	$	26,357		$	42,431

Inventories

Inventories consist of equipment used in developing oil and gas properties of $2,664 and $5,029 at December 31, 2004 and 2005, respectively, and product of $932 and $1,759 at December 31, 2004 and 2005, respectively. Inventories consist of equipment used in developing oil and gas properties of $5,334 and product of $1,726 at March 31, 2006. Equipment inventory is carried at

F1-8

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

the lower of cost or market using the specific identification method. Product inventories are stated at the lower of production cost or market.

Property and Equipment

Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently.

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives are as follows:

Furniture and fixtures	10 years
Automobiles and trucks	5 years
Machinery and equipment	10 - 20 years
Office and computer equipment	5 - 10 years
Building and improvements	10 - 40 years

Oil and Gas Properties

The Company uses the full-cost method of accounting for oil and gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the exploration for and development of oil and gas reserves. Proceeds from disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

Depreciation, depletion and amortization of oil and gas properties are provided using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. Depreciation, depletion and amortization expense of oil and gas properties was $8,144, $14,596, and $27,650 for the years ended December 31, 2003, 2004, and 2005, respectively. Depreciation, depletion and amortization expense of oil and gas properties was $5,330 and $9,974 for the three months ended March 31, 2005 and 2006, respectively.

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, with the full cost method of accounting

F1-9

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling test and depletion of oil and gas properties should be calculated in accordance with the provisions of SFAS No. 143. The Company adopted SAB No. 106 prospectively in the fourth quarter of 2004. However, this adoption did not materially impact the full cost ceiling test calculation or depletion for 2004.

In accordance with the full-cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for the Company’s cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties.

Impairment of Long-Lived Assets

Impairment losses are recorded on property and equipment used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Deferred Income Taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. The Company records a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

Revenue Recognition

Oil revenue is recognized when the product is delivered to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed.

Gas Balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Company recognizes gas imbalances on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for the Company’s obligation for natural gas taken by its purchasers which exceeds the Company’s ownership interest of the well’s total production. The Company’s

F1-10

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

aggregate imbalance due to over production is approximately 1,336,000 thousand cubic feet (mcf), 1,027,000 mcf, and 1,866,000 mcf at December 31, 2003, 2004, and 2005, respectively. The Company’s aggregate imbalance due to under production is approximately 1,919,000 mcf, 1,508,000 mcf, and 3,313,000 mcf at December 31, 2003, 2004, and 2005, respectively.

Hedge Transactions

The Company uses price swaps to reduce the effect of fluctuations in crude oil and natural gas prices. The Company accounts for these transactions in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires that the Company recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation. Derivatives that are not hedges must be adjusted to fair value through income.

If the derivative qualifies as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be offset against the change in fair value of the hedged assets, liabilities or firm commitments through income, or will be recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, will be immediately recognized in income. If it is probable the oil or gas sales which are hedged will not occur or the hedge is not highly effective, hedge accounting is discontinued and the effect is immediately recognized in income.

Under SFAS No. 133, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2003, 2004, or 2005. The ineffective portions of derivative gains or losses are reported in loss from oil and gas hedging activities on the consolidated statements of income.

Asset Retirement Obligations

On January 1, 2003, the Company adopted SFAS No. 143, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of income. The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules.

F1-11

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Upon adoption in 2003, the Company recorded a net asset of $4,437, a related liability of $5,861 (using an 8.5% discount rate) and a cumulative loss effect of accounting change of $887, net of tax benefit of $537.

The activity incurred in the asset retirement obligation for the years ended December 31, 2004 and 2005 and the three months ended March 31, 2006 is as follows:

	As of December 31,						As of March 31,
	2004			2005			2006
Beginning balance	$	7,816		$	10,324		$	15,796
Liabilities incurred in current period		775			1,094			235
Liabilities acquired (see note 2)		—			1,721			—
Liabilities settled in current period		(375	)		(264	)		(49	)
Accretion expense		768			1,056			342
Revisions of estimated cash flows		1,340			1,865			—
Ending ARO balance		10,324			15,796			16,324
Less current portion		262			346			364
	$	10,062		$	15,450		$	15,960

Environmental Liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2003, 2004 and 2005, the Company has not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon financial position, operating results, or the cash flows of the Company.

Recently Issued Accounting Standards

In May 2005, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 154, Accounting Changes and Error Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 requires voluntary changes in accounting principles to be applied retrospectively, unless it is impracticable. SFAS No. 154’s retrospective application requirement replaces APB 20’s requirement to recognize most voluntary changes in accounting principle by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. If retrospective application for all prior periods is impracticable, the method used to report the change and the reason the retrospective application is impracticable are to be disclosed.

Under SFAS No. 154, retrospective application will be the transition method in the unusual instance that a newly issued accounting pronouncement does not provide specific transition

F1-12

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

guidance. It is expected that many pronouncements will specify transition methods other than retrospective. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005, and the adoption of this statement is expected to have no impact on our financial position or results of operations.

The FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on our financial position, results of operations or cash flows.

Recently Adopted Accounting Standards

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. SFAS No. 123(R) amends SFAS No. 123, Accounting for Stock-Based Compensation, and Accounting Principles Board Opinion 25, Accounting for Stock Issued to Employees. SFAS No. 123(R) requires that the cost of share-based payment transactions (including those with employees and nonemployees) be recognized in the financial statements. The Company adopted SFAS No. 123(R) as of January 1, 2006 and, for stock awards on and after that date, the Black-Scholes option pricing model will be used to value those stock awards. The adoption of SFAS No. 123(R) did not have a material effect on the Company’s financial statements.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29. SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Company adopted this statement in the third quarter of 2005, and it did not have a material effect on its financial statements.

Note 2: Acquisition of CEI Bristol Acquisition, L.P.

On September 30, 2005, the Company acquired the 99% limited partner interest in CEI Bristol Acquisition, L.P., or CEI Bristol, from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. CEI Bristol owns properties primarily located in the Mid-Continent area of Oklahoma and Permian Basin areas of West Texas. As a result of the acquisition, the Company expects to increase production in 2006.

F1-13

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Prior to the acquisition, the Company held a 1% general partner interest through its wholly-owned subsidiary Chaparral Oil, L.L.C. The Company accounted for its investment in CEI Bristol under the equity method. The investment was $741 as of December 31, 2004 and is included in other assets. As a result of the acquisition, CEI Bristol became one of the Company’s wholly-owned subsidiaries and its results have been included in the consolidated statement of income from that date. Total consideration paid by the Company was approximately $158,108, subject to certain purchase price adjustments. The acquisition cost was funded with proceeds from a $132,000 bridge loan facility with General Electric Capital Corporation, borrowings from the Company’s revolving line of credit and cash on hand. As part of the acquisition, the Company acquired hedge liabilities of $42,108 that were not designated as hedges and were settled on October 3, 2005.

The acquisition was accounted for using the purchase method in accordance with the provisions of SFAS No. 141, Business Combinations. The estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition are as follows:

Oil and gas properties	$	152,945
Other current assets, including cash of $44,486		53,363
Accounts payable and accrued expenses		(4,371	)
Hedge liabilities		(42,108	)
Asset retirement obligations		(1,721	)
Net assets acquired	$	158,108

The unaudited pro forma information of the Company set forth below includes the operations of Chaparral and CEI Bristol for the years ended December 31, 2004 and 2005 as if the acquisition occurred on January 1, 2004. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

	Year ended December 31, 2004				Year ended December 31, 2005
(dollars in thousands, except per share data)	As reported		Pro forma		As reported		Pro forma
Revenue	$	92,196	$	125,614	$	133,086	$	150,023
Net income	$	17,715	$	20,166	$	12,850	$	9,697

F1-14

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 3: Property and equipment

Major classes of property and equipment consist of the following at December 31:

	2004		2005
Furniture and fixtures	$	885	$	974
Automobiles and trucks		4,164		5,544
Machinery and equipment		6,165		7,832
Office and computer equipment		3,645		4,216
Building and improvements		10,860		11,471
		25,719		30,037
Less accumulated depreciation and amortization		6,619		8,745
		19,100		21,292
Land		820		1,136
	$	19,920	$	22,428

Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:

	2004		2005
Office and computer equipment	$	1,702	$	1,785
Machinery and equipment		82		82
		1,784		1,867
Less accumulated depreciation and amortization		676		1,024
	$	1,108	$	843

Note 4: Hedge activities and financial instruments

Hedge Activities

The results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of this exposure, the Company has entered into derivative contracts designated as cash flow hedges. All derivative instruments have been entered into and designated as hedges of oil and gas price risk and not for speculative or trading purposes. As of December 31, 2005, the Company’s derivative instruments were comprised of oil and gas swaps. For swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

F1-15

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

The Company pays the counterparty the excess of the commodity market price over the fixed price and will receive the excess of the fixed price over the market price, as defined in each instrument. The estimated fair values of derivative instruments as of December 31, 2004 were liabilities of $5,152 and $16,083 for gas swaps and oil swaps, respectively. The estimated fair values of derivative instruments as of December 31, 2005 were liabilities of $60,158 and $33,952 for gas swaps and oil swaps, respectively. The carrying values of these instruments are equal to the estimated fair values. Hedge settlement payments of $3,833 and $8,088 were included in accounts payable and accrued liabilities for the years ended December 31, 2004 and 2005, respectively.

The fair value of the derivative instruments was established using appropriate valuation methodologies in accordance with SFAS No. 133. The actual effect on future results of operations will be based on the market prices at the time of settlement and may be more or less than fair value estimates used at the balance sheet date.

Hedge loss is reported in loss from oil and gas hedging activities in the consolidated statements of income and is comprised of the following:

	Year Ended December 31,						Three Months Ended March 31,
	2003		2004		2005		2005		2006
Reclassification of settled contracts	$	11,800	$	20,746	$	53,584	$	4,472	$	8,545
Loss (gain) on ineffective portion of derivatives qualifying for hedge accounting		420		604		14,740		4,367		(7,392	)
	$	12,220	$	21,350	$	68,324	$	8,839	$	1,153

Based upon the market prices at March 31, 2006 the Company expects to charge $20,215 of the balance in accumulated other comprehensive loss to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of December 31, 2005 are expected to be settled by December 2008.

Fair Value of Financial Instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2004 and 2005 approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2005, the carrying value of the 8 ¹/2% Senior Notes due 2015 approximates fair value.

Fair value amounts have been estimated using available market information and valuation methodologies. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

F1-16

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of hedge instruments and accounts receivable. Hedge instruments are exposed to credit risk from counterparties. Counterparties to the Company’s hedge instruments are primarily affiliates of its lenders and, therefore, the Company believes the counterparty risk is not significant. Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties the Company operates. The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

Sales of oil and natural gas to one purchaser accounted for 23.8%, 15.9% and 14.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the years ended December 31, 2003, 2004 and 2005, respectively. If the Company were to lose a purchaser, we believe we could identify a substitute purchaser.

F1-17

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 5: Long-term debt

Long-term debt consists of the following:

	December 31,
	2004		2005
Revolving credit line with banks(1)	$	164,389	$	109,000
Real estate mortgage note, payable in monthly installments of $53, bearing interest at the national prime rate plus 0.25% adjusted annually (effective rate of 5.25% at December 31, 2004) modified to LIBOR plus 2.66% during 2005 (effective rate of 5.79% at December 31, 2005), due August 31, 2010; collateralized by real property		6,549		6,212
Real estate mortgage note, payable in monthly installments of $3, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2004 and 2005), adjusted and fixed every five years with a floor rate of 7%, due January 11, 2017; collateralized by real property		267		251
Real estate mortgage note, payable in monthly installments of $1, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2004 and 2005), adjusted and fixed every five years with a floor rate of 7%, due May 15, 2017; collateralized by real property		84		79
Real estate mortgage note, payable in monthly installments of $2, bearing interest at 4.75%, due May 1, 2019; collateralized by real property		254		—
Real estate mortgage note, interest only monthly payments beginning August 5, 2005 at 6.04% with lump sum principal payment due at maturity, July 5, 2006; collateralized by real property		—		400
Installment note payable to bank, payable in monthly installments of $3, bearing interest at 8%, due July 15, 2006; collateralized by real property		57		22
Installment note payable, principal and interest payable quarterly in varying amounts, noninterest-bearing (discounted at 5.5% and 5.6% at December 31, 2004 and 2005, respectively), due December 2007		1,237		847
Installment note payable, principal and interest payable in annual installments of $550, noninterest-bearing (discounted at 5.5% and 5.6% at December 31, 2004 and 2005, respectively), due September 2007		1,290		895
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.62% to 8.612%, due January 2005 through November 2010; collateralized by automobiles, machinery and equipment		1,787		3,501
		175,914		121,207
Less current maturities		1,728		2,991
	$	174,186	$	118,216

(1) In 2005, the Company entered into a Sixth Restated Credit Agreement, which provides for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base has been determined based on reserve value, among other

F1-18

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

factors. The borrowing base was $186,000 at December 31, 2004 and was scheduled to mature in June 2006. Under the restated credit agreement, the borrowing base was $172,500 at December 31, 2005 and matures in June 2009. Effective May 25, 2006, the borrowing base was adjusted to $200,000. Interest was paid quarterly on $90,000 and $66,389 based upon various LIBOR options as of December 31, 2004 (effective rate of 4.06% and 4.71%, respectively) and on $8,000 based on prime plus varying margins as of December 31, 2004 (effective rate of 5.75%). Under the restated credit agreement, interest is paid at least every three months on $94,000 and $15,000 based upon various LIBOR options as of December 31, 2005 (effective rate of 5.94% and 5.88%, respectively). The credit line is collateralized by the Company’s oil and gas properties. Under the terms of the agreement, dividends may not exceed $350 per quarter. The agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting. The Company believes it was in compliance with the financial covenants at December 31, 2004 and December 31, 2005.

Interest of $155, $107 and $3 was capitalized during the years ended December 31, 2003, 2004 and 2005, respectively, primarily related to the construction of the Company’s office building and other construction projects.

Maturities of long-term debt as of December 31, 2005 are as follows:

2006	$	2,991
2007		2,522
2008		1,086
2009		109,545
2010		4,855
2011 and thereafter		208
	$	121,207

Note 6: Capital leases

Future minimum lease payments under capital leases for property and equipment and the present value of the net minimum lease payments as of December 31, 2005 are as follows:

Year ending December 31,
2006	$	153
2007		107
2008		88
2009		19
Total minimum lease payments		367
Less amount representing interest		30
Present value of net minimum lease payments		337
Less current portion		135
	$	202

F1-19

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 7: Issuance of 8 ¹/2% Senior Notes, due 2015

On December 1, 2005, the Company issued $325,000 of 8.5% senior notes due 2015 at a price of 100% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to repay the $132,000 bridge loan facility with General Electric Capital Corporation and to pay down debt under our revolving credit line.

Interest is payable on the senior notes semi-annually on June 1 and December 1 each year beginning June 1, 2006. The senior notes mature on December 1, 2015. On or after December 1, 2010, the Company, at its option, may redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.25% after December 1, 2010, 102.83% after December 1, 2011, 101.42% after December 31, 2012, and 100% after December 1, 2013 and thereafter. Prior to December 1, 2008, the Company may redeem up to 35% of the senior notes with the net proceeds of one or more equity offerings at a redemption price of 108.5%, plus accrued and unpaid interest.

The indenture contains certain covenants which limit the Company’s ability to:

• incur or guarantee additional debt and issue certain types of preferred stock;

• pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated debt;

• make investments;

• create liens on assets;

• create restrictions on the ability of restricted subsidiaries to pay dividends or make other payments to us;

• transfer or sell assets;

• engage in transactions with affiliates;

• consolidate, merge or transfer all or substantially all assets and the assets of subsidiaries; and

• enter into other lines of business.

In connection with the issuance of the senior notes, the Company capitalized $9,195 of costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized costs of $9,147 as of December 31, 2005 that are included in other assets. Amortization of $48 was charged to interest expense during the year ended December 31, 2005 related to these costs.

Chaparral is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries. Oklahoma Ethanol, a 66.67% owned subsidiary, has no significant operations or capitalization and is not a restricted subsidiary or guarantor of the notes.

F1-20

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 8: Income taxes

Income tax expense consists of the following for the years ended December 31:

	2003		2004		2005
Current tax expense (benefit)	$	—	$	5	$	(328	)
Deferred tax expense		6,932		9,875		7,637
	$	6,932	$	9,880	$	7,309

Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:

	2003		2004		2005
Statutory rate	35.0%		35.0%		35.0%
State income taxes, net of federal benefit	2.6%		2.6%		3.6%
Statutory depletion	(0.2%	)	(0.2%	)	(1.0%	)
Other	0.3%		(1.6%	)	(1.3%	)
Effective tax rate	37.7%		35.8%		36.3%

Components of the deferred tax assets and liabilities are as follows at December 31:

	2004			2005
Deferred tax assets related to
Hedge instruments	$	8,414		$	36,391
Asset retirement obligations		899			1,038
Accrued expenses, allowance and other		331			698
Net operating loss carryforwards
Federal		6,973			8,195
State		3,008			4,928
Statutory depletion carryforwards		510			1,175
Alternative minimum tax credit carryforwards		206			204
		20,341			52,629
Less: valuation allowance		1,881			3,289
		18,460			49,340
Deferred tax liabilities related to
Property and equipment		(35,324	)		(51,248	)
Inventories		(350	)		(667	)
		(35,674	)		(51,915	)
Net deferred tax liabilities	$	(17,214	)	$	(2,575	)

F1-21

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Approximately $5,192 and $24,034 of the current deferred tax asset at December 31, 2004 and 2005, respectively, relates to the short-term hedge instruments. Additionally, approximately $99 and $23 of the current deferred tax asset relates to asset retirement obligations at December 31, 2004 and 2005, respectively. At December 31, 2004 and 2005, taxes receivable of $118 and $120, respectively, are included in accounts receivable.

The Company has federal net operating loss carryforwards of approximately $23 million at December 31, 2005, which will begin to expire in 2008 if unused. At December 31, 2005, the Company has state net operating loss carryforwards of approximately $87 million, which will begin to expire in 2006. At December 31, 2005, approximately $58 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on the Company’s assessment that it is more likely than not that a portion will not be realized. In addition, at December 31, 2005, the Company had tax percentage depletion carryforwards of approximately $3,357 which are not subject to expiration.

Note 9: Related party transactions

Prior to the September 30, 2005 acquisition of the 99% limited partner’s interest, the Company managed, administered and operated the properties and business and affairs of CEI Bristol. At December 31, 2004, the Company had accounts receivable of $1,444 due from CEI Bristol. The Company acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were $939 and $1,018 for the years ended December 31, 2003 and 2004, respectively, and $735 for the nine months ended September 30, 2005. Additionally, the Company was compensated for management services provided to CEI Bristol through a management fee. Management fees earned by the Company were $89 and $228 for the years ended December 31, 2003 and 2004, respectively, and $111 for the nine months ended September 30, 2005.

On December 28, 2005, the Company’s chief executive officer acquired the Company’s beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112,475 in cash together with the assumption of a loan, which represents the Company’s net book value and its estimated current fair market value. The house was acquired by the Company in April 2004 for the purchase price of $327,500. Record title was taken in the name of the Company’s chief executive officer, who entered into a mortgage securing a $262,000 loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral enjoyed the use of the house, the Company’s board of directors approved the payment by the Company of the downpayment on the house and the principal and interest payments on the loan. The Company made monthly payments of principal and interest totaling approximately $37,697 through November 2005.

Note 10: Deferred compensation

Effective January 1, 2004, the Company implemented a Phantom Unit Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom units may

F1-22

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

be awarded to participants in total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Payment is not required by the participant upon redemption.

Prior to January 1, 2006, the Company accounted for our deferred compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which requires that this award be measured at the end of each period based on the current calculated fair value of the award. As prescribed by the Plan, fair market value is calculated based on the Company’s total asset value less total liabilities, with both assets and liabilities being adjusted to fair value. The primary adjustment required is the adjustment of oil and gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips.

Compensation expense is recognized over the vesting period of the phantom units and is reflected in general and administrative expenses in the income statement. The Company recognized deferred compensation expense of $120 and $525 for the years ended December 31, 2004 and 2005.

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123(R), using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes compensation costs for all phantom units granted prior to, but not yet vested as of January 1, 2006 and phantom units granted subsequent to January 1, 2006, based on the fair value estimated in accordance with SFAS No. 123(R). Since the phantom units are liability awards, fair value of the units is remeasured at the end of each reporting period until settlement. Prior to the settlement, the cost is recognized proportionately over the employees’ requisite service period, and once that period is over and the awards are fully vested, participants are paid the value of their phantom units in cash immediately. Results for prior periods have not been restated and the Company had no cumulative effect adjustment upon adoption of SFAS No. 123(R) under the modified-prospective method. The Company recognized deferred compensation expense of $110 for the three months ended March 31, 2006.

Prior to the adoption of SFAS No. FAS123(R), the Company presented all tax benefits of deductions resulting from the phantom unit plan as operating cash flows in the Consolidated Statement of Cash Flows. SFAS No. 123(R) requires the cash flows resulting from tax benefits of tax deductions in excess of the compensation cost recognized (excess tax benefits) to be classified as financing cash flows.

F1-23

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

A summary of the Company’s phantom unit activity as of December 31, 2005, and changes during the first quarter of fiscal year 2006 is presented in the following table:

	Fair Value		Phantom Units	Weighted average remaining contract term	Aggregate intrinsic value
	(Per share)
Unvested and total outstanding at December 31, 2005	$	17.89	164,906
Granted	$	17.89	21,357
Vested	$	17.89	52
Forfeited	$	17.89	1,407
Unvested and total outstanding at March 31 , 2006	$	17.75	184,804	5.38	$	3,280

Upon vesting, the Company is required to redeem all units. Accordingly, the contract term and the vesting period are the same. There are no vested units as of March 31, 2006.

The fair value of each unit award is estimated on the date of grant using the Black-Scholes option pricing model, which uses the assumptions in the following table:

	Quarter Ended
	March 31, 2006
Dividend yield	0.0%
Volatility	81.0%
Risk-free interest rate	4.83%
Expected life (in years)	4-6.75

The Company estimated volatility based on an average of the volatilities of similar public entities whose share prices are publicly available over the expected life of the granted units. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected term of the option. The expected dividend yield is based on the Company’s current dividend yield and the best estimate of projected dividend yield for future periods within the expected life of the option.

As of March 31, 2006, there was approximately $2,551 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 5.38 years.

Note 11: Retirement benefits

The Company provides a 401(k) retirement plan for all employees with at least one month of service. The Company matches employee contributions 100%, up to 5% of each employee’s gross

F1-24

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

wages. At December 31, 2003, 2004 and 2005, there were 191, 207 and 256 employees, respectively, participating in the plan. Contributions recognized by the Company totaled $465, $544 and $682 for the years ended December 31, 2003, 2004 and 2005, respectively.

Note 12: Commitments and contingencies

Standby Letters of Credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. The Company had various Letters outstanding totaling $800, $990 and $990 as of December 31, 2003, 2004, and 2005, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 7.25% at December 31, 2005) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during 2003, 2004, or 2005.

The Company has entered into operating lease agreements for the use of office space and equipment rental on oil and gas properties. Rent expense for the years ended December 31, 2003, 2004, and 2005 was $568, $486, and $327, respectively.

In August 2005, the Company entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma Farmers Union Sustainable Energy LLC to construct and operate an ethanol production plant in Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of ethanol, 176,000 tons of distillers dried grains and 2.8 Bcfe of CO₂ per year. The Company will have the option to acquire all or part of this CO₂ for use in its tertiary oil recovery projects. The start up and construction costs are estimated to be between $90 and $95 million, with the Company having a 66.67% ownership interest. The Company expects Oklahoma Ethanol L.L.C. will receive between $54 and $57 million in secured indebtedness with recourse limited to the Company’s interests in this entity to fund construction costs and for related start-up working capital. The Company expects to enter into a construction contract in 2006 and expects construction to commence in late 2006 or early 2007 with completion in 2008, and that its equity contribution will be approximately $24 to 25.3 million.

The Company has an employment agreement with its chief financial officer which provides for an annual base salary, bonus compensation, phantom units and various benefits. The agreement provides for a minimum severance amount of $424 in the event of termination without cause, change of control, or termination, liquidation or dissolution of the Company. The severance agreement expires June 30, 2010.

Various claims and lawsuits, incidental to the ordinary course of business, are pending both for and against the Company. In the opinion of management, all matters are not expected to have a material effect on the Company’s consolidated financial position or consolidated results of operations.

F1-25

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 13: Oil and gas activities

The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows for the years ended December 31:

	2003		2004		2005
Property acquisition costs(1)	$	19,864	$	30,546	$	222,285
Development costs		36,758		62,371		103,479
Exploration costs		340		3,114		7,274
Total	$	56,962	$	96,031	$	333,038

(1) Includes $152,945 of costs related to the acquisition of CEI Bristol in 2005.

The average depreciation, depletion and amortization rate per equivalent unit of production was $0.53, $0.77 and $1.09 for the years ended December 31, 2003, 2004 and 2005, respectively.

Oil and gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties, exploratory wells in progress, and secondary recovery projects before the assignment of proved reserves. Of the $10,150 of unproved property costs at December 31, 2005 being excluded from the amortization base, $495, $1,994 and $7,372 were incurred in 2003, 2004 and 2005, respectively, and $289 was incurred in prior years. These costs are primarily seismic and lease acquisition costs. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to five years.

Note 14: Disclosures about oil and gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Lee Keeling and Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

F1-26

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

The Company’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2003, 2004 and 2005 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2003	16,243		151,773		249,231
Purchase of minerals in place	4,273		24,877		50,515
Sales of minerals in place	(118	)	(463	)	(1,171	)
Extensions and discoveries	254		11,242		12,766
Revisions	(3,498	)	21,090		102
Improved recoveries	547		4,920		8,202
Production	(924	)	(9,762	)	(15,306	)
Balance at December 31, 2003	16,777		203,677		304,339
Purchase of minerals in place	3,724		39,894		62,238
Sales of minerals in place	(91	)	(201	)	(747	)
Extensions and discoveries	1,589		24,470		34,004
Revisions	2,051		2,229		14,535
Improved recoveries	5,708		5,474		39,722
Production	(1,173	)	(11,923	)	(18,961	)
Balance at December 31, 2004	28,585		263,620		435,130
Purchase of minerals in place	7,399		128,782		173,176
Sales of minerals in place	(45	)	(97	)	(367	)
Extensions and discoveries	569		19,117		22,531
Revisions	(1,975	)	4,334		(7,516	)
Improved recoveries	829		15,288		20,262
Production	(1,449	)	(16,660	)	(25,354	)
Balance at December 31, 2005	33,913		414,384		617,862
Proved developed reserves:
December 31, 2003	14,314		160,662		246,546
December 31, 2004	17,358		186,544		290,692
December 31, 2005	23,762		283,173		425,745

The following information was developed using procedures prescribed by SFAS No. 69. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

F1-27

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

The Company believes that, in reviewing the information that follows, the following factors should be taken into account:

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

• future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 4, “Hedge Activities and Financial Instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

	2003			2004			2005
Future cash flows	$	1,678,196		$	2,757,761		$	5,537,226
Future production costs		(560,129	)		(908,239	)		(1,599,503	)
Future development and abandonment costs		(64,443	)		(186,381	)		(340,423	)
Future income tax provisions		(357,409	)		(567,468	)		(1,212,513	)
Net future cash flows		696,215			1,095,673			2,384,787
Less effect of 10% discount factor		(370,965	)		(581,632	)		(1,316,899	)
Standardized measure of discounted future net cash flows	$	325,250		$	514,041		$	1,067,888

F1-28

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(information as of March 31, 2006 and for the three months ended March 31, 2005 and 2006 is unaudited)

(dollars in thousands, unless otherwise noted)

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were included in the computation, then future cash flows would have decreased by $23,208, $29,332, and $44,935 in 2003, 2004 and 2005, respectively.

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

	2003			2004			2005
Beginning of year	$	218,266		$	325,250		$	514,041
Sale of oil and gas produced, net of production costs		(49,826	)		(78,472	)		(144,637	)
Net changes in prices and production costs		101,115			89,687			477,828
Extensions and discoveries		22,194			56,933			83,727
Improved recoveries		22,546			73,199			68,467
Changes in future development costs		(14,083	)		(69,721	)		(140,394	)
Development costs incurred during the period that reduced future development costs		5,601			11,230			8,456
Revisions of previous quantity estimates		186			32,775			(25,195	)
Purchases and sales of reserves in place, net		81,077			109,754			496,645
Accretion of discount		32,065			49,565			78,483
Net change in income taxes		(64,588	)		(99,260	)		(276,722	)
Changes in production rates and other		(29,303	)		13,101			(72,811	)
End of year	$	325,250		$	514,041		$	1,067,888

Average prices in effect at December 31, 2003, 2004 and 2005 used in determining future net revenues related to the standardized measure calculation are as follows:

	2003		2004		2005
Oil (per Bbl)	$	32.52	$	43.51	$	61.04
Gas (per Mcf)	$	6.19	$	6.35	$	10.08

Note 15: Comprehensive loss (unaudited)

Components of comprehensive income (loss), net of related tax, are as follows for the three months ended March 31.

	2005			2006
Net income	$	3,263		$	10,372
Unrealized gain (loss) on hedges		(31,457	)		10,576
Reclassification adjustment for hedge losses included in net income		2,745			5,245
Comprehensive gain (loss)	$	(25,449	)	$	26,193

F1-29

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements—(continued)

(dollars in thousands, unless otherwise noted)

Note 16: Subsequent events

The Company has filed a registration statement for its initial public offering and, if completed, will effect a stock split prior to completion of that offering.

F1-30

Report of independent registered public accounting firm

General Partner

CEI Bristol Acquisition, LP

We have audited the accompanying balance sheets of CEI Bristol Acquisition, LP as of December 31, 2003 and 2004, and the related statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Partnership’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. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial position of CEI Bristol Acquisition, LP as of December 31, 2003 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, effective January 1, 2003, the Partnership changed its method of accounting for asset retirement obligations.

/s/    GRANT THORNTON LLP

Oklahoma City, Oklahoma

September 28, 2005

F2-1

CEI Bristol Acquisition, LP

Balance sheets

	December 31,						September 30,
(in thousands)	2003			2004			2005
							(unaudited)
Assets
Current assets
Cash and cash equivalents	$	1,897		$	2,804		$	44,486
Accounts receivable		10,482			6,697			7,201
Other assets		262			1,282			520
Total current assets		12,641			10,783			52,207
Oil & gas properties, net, using the successful efforts methods		56,942			56,328			61,869
Other assets		10			3			—
	$	69,593		$	67,114		$	114,076
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	6,450		$	2,986		$	5,316
Current portion of notes payable		—			—			16,000
Short-term hedge instruments		8,006			10,387			42,108
Total current liabilities		14,456			13,373			63,424
Hedge instruments		9,641			11,295			—
Asset retirement obligations		215			254			1,001
Partners’ capital
Limited and general partners		61,893			63,221			88,949
Accumulated other comprehensive loss		(16,612	)		(21,029	)		(39,298	)
		45,281			42,192			49,651
	$	69,593		$	67,114		$	114,076

The accompanying notes are an integral part of these statements.

F2-2

CEI Bristol Acquisition, LP

Statements of operations

	Year ended December 31,									Nine months ended September 30,
(in thousands)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Revenues
Oil and gas sales	$	21,682		$	31,423		$	44,310		$	33,148		$	29,773
Hedge loss		(1,892	)		(9,424	)		(10,892	)		(7,767	)		(12,836	)
Total revenues		19,790			21,999			33,418			25,381			16,937
Costs and expenses
Lease operating		9,767			7,128			9,507			6,617			6,867
Production tax		2,028			2,401			3,605			2,590			2,458
Depreciation, depletion and amortization		7,135			5,430			8,571			6,143			4,818
Impairment of oil and gas properties		1,783			3,764			2,180			1,134			—
General and administrative		180			202			351			303			196
Total costs and expenses		20,893			18,925			24,214			16,787			14,339
Operating income (loss)		(1,103	)		3,074			9,204			8,594			2,598
Other income (expense)		509			43			123			(39	)		20
Income (loss) before accounting change		(594	)		3,117			9,327			8,555			2,618
Cumulative effect of change in accounting principal		—			(35	)		—			—			—
Net income (loss)	$	(594	)	$	3,082		$	9,327		$	8,555		$	2,618

The accompanying notes are an integral part of these statements.

F2-3

CEI Bristol Acquisition, LP

Statement of partners’ capital

Years ended December 31, 2002, 2003, and 2004 and for the nine-month period ended September 30, 2005

(unaudited)

(in thousands)	General Partner			Limited Partner			Accumulated other comprehensive loss			Total
Balance at January 1, 2002	$	625		$	61,873		$	(3,713	)	$	58,785
Net loss		(6	)		(588	)		—			(594	)
Other comprehensive loss
Reclassification adjustment for hedge losses		—			—			1,804			1,804
Unrealized loss on hedges		—			—			(11,621	)		(11,621	)
Total comprehensive loss											(10,411	)
Distributions		(39	)		(3,812	)		—			(3,851	)
Contributions		20			1,970			—			1,990
Balance at December 31, 2002		600			59,443			(13,530	)		46,513
Net income		31			3,051			—			3,082
Other comprehensive loss
Reclassification adjustment for hedge losses		—			—			8,477			8,477
Unrealized loss on hedges		—			—			(11,559	)		(11,559	)
Total comprehensive loss											—
Distributions		(85	)		(8,464	)		—			(8,549	)
Contributions		73			7,244			—			7,317
Balance at December 31, 2003		619			61,274			(16,612	)		45,281
Net income		93			9,234			—			9,327
Other comprehensive income
Reclassification adjustment for hedge losses		—			—			11,273			11,273
Unrealized loss on hedges		—			—			(15,690	)		(15,690	)
Total comprehensive income											4,910
Distributions		(152	)		(15,082	)		—			(15,234	)
Contributions		72			7,163			—			7,235
Balance at December 31, 2004		632			62,589			(21,029	)		42,192
Net income (unaudited)		26			2,592			—			2,618
Other comprehensive loss (unaudited)
Reclassification adjustment for hedge losses		—			—			10,679			10,679
Unrealized loss on hedges		—			—			(28,948	)		(28,948	)
Total comprehensive loss											(15,651	)
Distributions (unaudited)		(63	)		(6,229	)		—			(6,292	)
Contributions (unaudited)		454			28,948			—			29,402
Balance at September 30, 2005 (unaudited)		1,049			87,900			(39,298	)		49,651

The accompanying notes are an integral part of these statements.

F2-4

CEI Bristol Acquisition, LP

Statements of cash flows

	Year ended December 31,									Nine months ended September 30,
(in thousands)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Cash flows from operating activities
Net income (loss)	$	(594	)	$	3,082		$	9,327		$	8,555		$	2,618
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		7,135			5,430			8,571			6,143			4,818
Cumulative effect of accounting change		—			35			—			—			—
Impairment on oil and gas properties		1,783			3,764			2,180			1,134			—
(Gain) loss on hedge ineffectiveness		88			947			(381	)		112			2,157
Gain on sale of oil and gas properties		(494	)		(37	)		(42	)		120			—
Change in assets and liabilities
Decrease (increase) in accounts receivable		(714	)		(6,440	)		3,785			3,865			(504	)
(Increase) decrease in other assets		37			72			(1,020	)		119			761
(Increase) decrease in accounts payable and accrued liabilities		(690	)		3,675			(3,469	)		(3,653	)		1,320
Net cash provided by operating activities		6,551			10,528			18,951			16,395			11,170
Cash flows from investing activities
Purchase of oil and gas properties		(8,112	)		(8,863	)		(10,444	)		(6,877	)		(8,598	)
Proceeds from dispositions of oil and gas properties		4,060			785			399			389			—
Net cash used in investing activities		(4,052	)		(8,078	)		(10,045	)		(6,488	)		(8,598	)
Cash flows from financing activities
Proceeds from notes payable		—			—			—			—			16,000
Distributions to partners		(3,851	)		(8,549	)		(15,234	)		(11,895	)		(6,292	)
Capital contributions		1,990			7,317			7,235			2,988			29,402
Net cash (used in) provided by financing activities		(1,861	)		(1,232	)		(7,999	)		(8,907	)		39,110
Net increase in cash and cash equivalents		638			1,218			907			1,000			41,682
Cash and cash equivalents at beginning of year		41			679			1,897			1,897			2,804
Cash and cash equivalents at end of year	$	679		$	1,897		$	2,804		$	2,897		$	44,486

The accompanying notes are an integral part of these statements.

F2-5

Supplemental Disclosure of Noncash Investing Activities

During the years ended December 31, 2003 and 2004 and the nine months ended September 30, 2005, the Partnership recorded an asset and related liability of $9, $34, and $1,674 associated with the asset retirement obligation on acquisition and/or development of oil and gas properties.

Effective on January 1, 2003, the Company recorded the cumulative effect of SFAS No. 143 for asset retirement obligations, as follows:

Increase in oil and gas properties	$	167
Increase in asset retirement obligations		(202	)
Cumulative effect of accounting change	$	(35	)

The accompanying notes are an integral part of these statements.

F2-6

CEI Bristol Acquisition, LP

Notes to financial statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of accounting policies

CEI Bristol Acquisition, LP (the “Partnership”) was organized effective February 10, 2000 under the laws of the state of Texas and commenced oil and gas operations on September 28, 2000. The Partner-ship is involved in the acquisition, drilling, development, and production of oil and gas properties.

The general partner receives 1% of revenue and expense items until repayment of the capital investment of the 99% limited partner. Once the limited partner has received cash distributions in the amount of capital contributions, plus amounts to yield an annual rate return of 11%, as defined by the “Cumulative Payout” agreement, the general partner will receive an additional 34% of revenues and expenses.

A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows.

Interim financial statements

The financial information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the nine month period ended September 30, 2005 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2005.

Use of estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management makes estimates based on knowledge and experience; accordingly, actual results could differ from those estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, asset retirement obligations and others, and are subject to change.

Cash and cash equivalents

The Partnership considers all highly liquid investments with maturities of three months or less to be cash equivalents.

The Partnership maintains its cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Partnership has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. At December 31, 2003 and 2004, the Partnership has cash and cash equivalents of approximately $1,472 and $2,380, respectively, at one financial institution. Cash and cash equivalents at September 30, 2005 included $42,108 used on October 3, 2005 to terminate the swaps.

F2-7

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

Accounts receivable

The Partnership has receivables from oil and gas purchasers which are generally uncollateralized. The Partnership generally reviews these parties for credit worthiness and general financial condition. The Partnership maintains its allowance by considering the length of time past due and previous loss history among other things.

Oil and gas properties

The Partnership uses the successful efforts method of accounting for oil and gas properties and activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells which result in the discovery of proved reserves, and to drill and equip developmental wells are capitalized. Costs relating to unsuccessful exploration, geological and geophysical costs, costs of carrying and retaining unproved properties, and costs of abandoned properties are expensed.

Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on estimates of proved reserve quantities. Capitalized exploration well costs and development costs (plus estimated future equipment dismantlement, surface restoration, and property abandonment costs, net of equipment salvage values) are amortized similarly by field based on estimates of proved reserve quantities. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized as income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

The Partnership periodically reviews the carrying value of proved oil and gas properties for impairment based upon the future estimated undiscounted cash flows from these properties on a field-by-field basis. The Partnership’s estimated future cash flows and reserve quantities are based upon the latest current market prices generally using forward pricing curves at the time the impairment is determined, which may or may not reflect prices at the Partnership’s year-end. Based on this review, the carrying value of proved oil and gas properties that could not be recovered through these estimated cash flows are reduced to their fair value based upon estimated cash flows discounted at 10%. Significant unproved properties are assessed periodically on a prospect-by-prospect basis and any decline in fair value below cost is recorded as impairment

F2-8

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

expense. Unproved properties which are not individually significant are periodically assessed for impairment on a field-by-field basis using the Partnership’s drilling history and lease period.

Income taxes

Income taxes on net income of the Partnership are payable by the partners. Accordingly, no provision has been made for federal or state income taxes.

Revenue recognition

Oil and natural gas revenue is recognized when the product is delivered to the purchaser.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Partnership recognizes income on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for the Partnership’s obligation for natural gas taken by its purchasers which exceeds the Partnership’s ownership interest of the well’s total production. The Partnership’s aggregate imbalance due to over production is approximately 360,000 thousand cubic feet (mcf) of gas and 343,000 mcf at December 31, 2003 and 2004, respectively. The Partnership’s aggregate imbalance due to under production is approximately 1,236,000 mcf and 1,134,000 mcf at December 31, 2003 and 2004, respectively.

Financial instruments

The Partnership’s financial instruments include cash and cash equivalents, receivables, and hedge instruments. The carrying amounts of cash and cash equivalents and receivables approximate fair value due to their short-term nature. Derivative instruments are carried at fair value.

Hedge transactions

The Partnership uses swaps and collars to reduce the effect of fluctuations in crude oil and natural gas prices. The Partnership accounts for these transactions in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires that the Partnership recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation. Derivatives that are not hedges must be adjusted to fair value through income.

If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities,

F2-9

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

or firm commitments through income or recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value will be immediately recognized in income.

Under SFAS No. 133, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2003 or 2004.

Asset retirement obligations

On January 1, 2003, the Partnership adopted SFAS No. 143 Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of income. The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules.

Upon adoption in 2003, the Partnership recorded a net asset of $167, a related liability of $202 (using an 8.5% discount rate) and a cumulative loss effect of accounting change of $35. The pro forma balance of the asset retirement obligation at January 1, 2002 and 2003 would have been $170 and $202, respectively, and pro forma net income (loss) would have been ($515) and $3,117 for the years ended December 31, 2002 and 2003, respectively.

The activity incurred in the asset retirement obligation since adoption is as follows:

	As of December 31,						As of September 30,
	2003			2004			2005
Beginning balance	$	—		$	222		$	264
Adoption of SFAS No. 143		202			—			—
Liabilities incurred in current period		9			5			—
Liabilities settled in current period		(6	)		(12	)		(8	)
Accretion expense		17			21			92
Revisions of estimated cash flows		—			28			1,673
Ending ARO balance		222			264			2,021
Less current portion		7			10			1,020
	$	215		$	254		$	1,001

F2-10

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

Recently issued accounting standards

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29. SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. The Partnership adopted this statement in the third quarter of 2005, and it did not have a material effect on its financial statements.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 supersedes SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and APB Opinion No. 20, Accounting Changes. SFAS No. 154 requires, unless impracticable, retrospective application to prior periods’ financial statements of changes in accounting principle. The provisions of SFAS No. 154 also require that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after December 15, 2005.

Reclassifications

Certain reclassifications have been made to prior year amounts to conform to current year presentation.

Note 2: Oil and gas properties

Oil and gas properties consist of the following at December 31:

	2003		2004
Leasehold costs	$	60,523	$	60,503
Tangible equipment costs		6,498		8,800
Intangible drilling costs		14,262		21,785
Asset retirement costs		171		196
		81,454		91,284
Less accumulated depletion, depreciation, and amortization		24,512		34,956
	$	56,942	$	56,328

Note 3: Hedging activities

The results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of this exposure, the Partnership has entered into derivative instruments. The Partnership’s derivative instruments covered approximately 56% and 44% of oil and gas production, respectively, for the year ended December 31, 2004. All derivative instruments have been entered into and designated as hedges of oil and gas price risk and not

F2-11

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

for speculative or trading purposes. As of December 31, 2004, the Partnership’s derivative instruments were comprised solely of swaps. For swap instruments, the Partnership receives a fixed price for the hedged commodity and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount to or from the counterparty. These swaps have been designated and have qualified as cash flow hedge instruments.

The estimated fair values of derivative instrument liabilities as of December 31, 2004 were approximately $4,595 and $17,087 for oil swaps and gas swaps, respectively. The carrying values of these instruments are equal to the estimated fair values. The fair value of the derivative instruments was established using appropriate valuation methodologies in accordance with SFAS No. 133, as amended. The actual contribution to future results of operations will be based on the market prices at the time of settlement and may be more or less than fair value estimates used at the balance sheet dates.

Hedge loss reported in oil and gas sales is comprised of the following for the years ended December 31:

	Year Ended December 31,							Nine Months Ended September 30,
	2002		2003		2004			2004		2005
								(unaudited)		(unaudited)
Reclassification of settled contracts	$	1,804	$	8,477	$	11,273		$	7,655	$	10,679
(Gain) loss on ineffective portion of derivative qualifying for hedge accounting		88		947		(381	)		112		2,157
	$	1,892	$	9,424	$	10,892		$	7,767	$	12,836

The Partnership expects to transfer approximately $24,649 of the balance in accumulated other comprehensive loss, based upon market prices at September 30, 2005, to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of September 30, 2005 are expected to occur by December 1, 2007.

Note 4: Related party transactions

The general partner manages, controls, administers, and operates the business affairs of the Partnership. The Partnership compensates the general partner for services provided to the Partnership through a management fee. Management fees paid by the Partnership were approximately $79, $89 and $228 for the years ended December 31, 2002, 2003 and 2004, respectively.

The parent company of the general partner acts as operator of certain Partnership wells and receives overhead reimbursements as provided in operating agreements. Fees paid for these

F2-12

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

overhead reimbursements were approximately $1,630, $939 and $1,018 for the years ended December 31, 2002, 2003 and 2004. At December 31, 2003 and 2004, the Partnership had accounts payable of approximately $5,332 and $1,444 respectively, due to the parent company of the general partner.

Note 5: Oil and gas activities

The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows for the years ended December 31:

	2002		2003		2004
Property acquisition costs	$	74	$	270	$	386
Development costs		7,684		8,610		9,903
Exploration costs		635		59		185
Asset retirement costs		—		171		25
Total	$	8,393	$	9,110	$	10,499

Net capitalized costs related to the Company’s oil and gas producing activities are summarized as follows:

	2003			2004
Proven oil and gas properties	$	81,450		$	91,272
Unproven oil and gas properties		4			12
Accumulated depreciation, depletion, and amortization		(24,512	)		(34,956	)
Oil and gas properties, net	$	56,942		$	56,328

Note 6: Disclosures about oil and gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Lee Keeling and Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

F2-13

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

The Partnership’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Partnership’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2002, 2003, and 2004 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2002	2,865		54,841		72,031
Purchase of minerals in place	270		9,763		11,383
Sales of minerals in place	(316	)	(3,868	)	(5,764	)
Extensions and discoveries	4		757		781
Revisions	618		5,711		9,419
Improved recoveries	183		1,941		3,039
Production	(346	)	(4,819	)	(6,895	)
Balance at December 31, 2002	3,278		64,326		83,994
Purchase of minerals in place	121		2,405		3,131
Sales of minerals in place	(19	)	(13	)	(127	)
Extensions and discoveries	63		3,298		3,676
Revisions	(556	)	2,110		(1,226	)
Improved recoveries	98		977		1,565
Production	(277	)	(4,268	)	(5,930	)
Balance at December 31, 2003	2,708		68,835		85,083
Purchase of minerals in place	143		6,334		7,192
Sales of minerals in place	—		—		—
Extensions and discoveries	19		4,014		4,128
Revisions	186		(471	)	645
Improved recoveries	58		642		990
Production	(275	)	(6,315	)	(7,965	)
Balance at December 31, 2004	2,839		73,039		90,073
Proved developed reserves:
December 31, 2002	3,057		56,511		74,853
December 31, 2003	2,550		61,691		76,991
December 31, 2004	2,568		58,918		74,326

The following information was developed using procedures prescribed by SFAS No. 69. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

F2-14

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

The Partnership believes that, in reviewing the information that follows, the following factors should be taken into account:

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

• future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 3, “Hedge Activities and Financial Instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

	2002			2003			2004
Future cash flows	$	362,422		$	440,169		$	530,846
Future production costs		(132,711	)		(157,055	)		(178,721	)
Future development and abandonment costs		(9,336	)		(8,419	)		(17,797	)
Net future cash flows		220,375			274,695			334,328
Less effect of 10% discount factor		(108,872	)		(134,255	)		(169,125	)
Standardized measure of discounted future net cash flows	$	111,503		$	140,440		$	165,203

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were

F2-15

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

(dollars in thousands, unless otherwise noted)

included in the computation, then future cash flows would have decreased by $19,908, $24,647 and $22,272 in 2002, 2003, and 2004, respectively.

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

	2002			2003			2004
Beginning of year	$	58,413		$	111,503		$	140,440
Sale of oil and gas produced, net of production costs		(9,887	)		(21,894	)		(31,198	)
Net changes in prices and production costs		15,318			9,439			9,986
Extensions and discoveries		1,296			5,123			2,471
Improved recoveries		8,683			9,664			5,696
Changes in future development costs		(5,207	)		2,501			(6,846	)
Development costs incurred during the period that reduced future development costs		194			1,361			2,491
Revisions of previous quantity estimates		9,681			(1,797	)		1,121
Purchases and sales of reserves in place, net		15,133			15,296			17,468
Accretion of discount		5,841			11,150			14,044
Changes in production rates and other		12,038			(1,906	)		9,530
End of year	$	111,503		$	140,440		$	165,203

Average prices in effect at December 31, 2002, 2003, and 2004 used in determining future net revenues related to the standardized measure calculation are as follows:

	2002		2003		2004
Oil (per Bbl)	$	31.23	$	32.55	$	43.46
Gas (per Mcf)	$	4.59	$	5.83	$	6.19

Note 7: Event (unaudited) subsequent to date of auditors report

On September 30, 2005, the limited partner interest of the Partnership was purchased by an affiliate of the general partner. As a part of the purchase, the Partnership borrowed $16,000 from General Electric Capital Corporation (GECC) and received a $26,108 contribution from the general partner. These proceeds were used to fund the settlement of the Partnership’s hedges on October 3, 2005. The $16,000 owed to GECC is part of a $132,000 note payable due June 30, 2006, bears interest at LIBOR plus 2% and is collateralized by the oil and gas properties of the Partnership.

On December 1, 2005, the parent company of the general partner issued 8 ¹/2% Senior Notes in the amount of $325,000, due December 1, 2015. The proceeds from the notes were used to pay the $132,000 note payable, including the $16,000 owed by the Partnership.

On December 31, 2005, the Partnership was dissolved and all assets were transferred to the parent of the general and limited partner or its subsidiaries.

F2-16

Prospectus

July 19, 2006

Until October 17, 2006, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.