Amendment No. 1 to Form S-4

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

Index to Financial Statements

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

Index to Financial Statements

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

See “ Risk factors” beginning on page 23 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.”

Index to Financial Statements

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 , 2008.

Index to Financial 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:

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 23 of this prospectus.

Index to Financial Statements

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 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.

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.

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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 subsidiaries.

In this prospectus, “pro forma basis” means after giving pro forma effect to (1) our 2006 acquisition of Calumet Oil Company and certain of its affiliates (2) our private issuance of common stock on September 29, 2006 for an aggregate purchase price of $102.0 million and the application of the net proceeds from such issuance and (3) the issuance of $325.0 million aggregate principal amount of our 8⁷/8% Senior Notes due 2017 on January 18, 2007 and the application of the net proceeds from the issuance of the notes. See “Significant developments, financings and acquisitions” 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

On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for a cash purchase price of approximately $500.0 million. Calumet owned properties are located principally in Oklahoma and Texas, areas which are located in our existing core areas of operations. As of December 31, 2006, estimated proved reserves attributable to the acquisition were approximately 346 Bcfe. Calumet’s proved reserves have a 33.8 year reserve life as of December 31, 2006 (calculated as December 31, 2006 reserves of 345,786 MMcfe divided by year ended December 31, 2006 production of 10,220 MMcfe) have relatively low production decline rates averaging 5.6% from 2008 - 2010 and are approximately 96% oil. In addition to increasing our average net daily production, many of the acquired properties have significant drilling and enhanced oil recovery opportunities, as further discussed in the “Properties” Section beginning on page 77.

Index to Financial Statements

As of December 31, 2006, we had estimated proved reserves of 906 Bcfe (69% proved developed and 59% crude oil) with a PV-10 value of approximately $1.5 billion. For the year ended December 31, 2006, our average daily production was 88.7 MMcfe and on a pro forma basis was 112.2 MMcfe, our estimated pro forma reserve life was 22.1 years (calculated as December 31, 2006 reserves of 905,579 MMcfe divided by year ended December 31, 2006 pro forma production of 40,953 MMcfe), and our revenues, on a pro forma basis, were $335.2 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.

The following table presents proved reserves and PV-10 value as of December 31, 2006, average daily production on an actual and pro forma basis for the year ended December 31, 2006, and average daily production for the nine months ended September 30, 2007 by our areas of operation.


	Proved reserves as of December 31, 2006						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, 2006	Year ended December 31, 2006	Nine months ended September 30, 2007

Mid-Continent	73,312	251,293	691,165	76.4%	$	1,087.4	53.3	76.8	72.3
Permian Basin	6,039	58,233	94,467	10.4%		170.6	15.1	15.1	17.6
Ark-La-Tex	1,077	18,919	25,381	2.8%		47.9	4.7	4.7	5.0
North Texas	2,324	5,008	18,952	2.1%		38.4	3.1	3.1	3.8
Rocky Mountains	3,563	7,679	29,057	3.2%		56.7	3.3	3.3	2.6
Gulf Coast	2,063	34,179	46,557	5.1%		93.1	9.2	9.2	9.6

Total	88,378	375,311	905,579	100.0%	$	1,494.1	88.7	112.2	110.9

Business strengths

Consistent track record of low-cost reserve additions and production growth. From 2003 to 2006, we have grown reserves and production by a compounded annual growth rate of 44% and 28%, 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 794%, 822% and 991%, as further discussed beginning on page 20, of our production in 2004, 2005 and 2006 respectively, at an average fully developed FD&A cost of $2.37 per Mcfe over this three-year period which we believe is among the lowest in the industry.

Index to Financial Statements

acquisitions of proved properties were $28.5 million, $216.7 million and $484.4 million, respectively. These acquisition capital expenditures represented approximately 30%, 65% and 73%, respectively, of our total capital expenditures and approximately 46%, 80% and 94%, respectively, of our increases in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. Excluding the acquisition of Calumet in October 2006, we spent $19.5 million on acquisitions of proved properties during 2006, representing approximately 10% of 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.

Inventory of drilling locations. As of December 31, 2006, we had an inventory of 741 proved developmental drilling locations and 2,647 additional potential drilling locations, which combined represent over 17 years of drilling opportunities based on our 2006 drilling rate as shown in the following table.


	Identified proved undeveloped drilling locations	Identified additional potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net

Mid-Continent	571	1,609	367,476	37,460
Permian Basin	65	807	50,518	17,883
Ark-La-Tex	6	18	14,190	—
North Texas	36	99	16,286	763
Rocky Mountains	56	73	13,995	9,256
Gulf Coast	7	41	45,503	9,139

Total	741	2,647	507,968	74,501

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 23. We have experienced a high historical drilling success rate of approximately 97% on a weighted average basis during 2004, 2005 and 2006. For the year ended December 31, 2006, we spent $133.5 million to drill 61 (48 net) operated wells and to participate in 131 (9.4 net) wells operated by others, representing 4% of our increases in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries. For 2007, we have budgeted $152.0 million to drill more than 125 operated wells and to participate in more than 140 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 42,400 square miles of 3-D seismic data, conducted four proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

Index to Financial Statements

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% 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, 2006, our proved reserves included four properties where CO₂ tertiary recovery methods are used, which comprise approximately 6% of our total proved reserves. With the acquisition of Calumet, and specifically the North Burbank Unit, our tertiary recovery assets include an enhanced oil recovery “EOR” polymer flood. The North Burbank Unit is in the early phases of an EOR polymer flood which was proven up by Phillips Petroleum Company through a pilot program in the mid 1980’s before being shut down due to low prevailing oil prices. We plan to expand this EOR program and ultimately to include CO₂ injection.

Experienced management team. Mark A. Fischer, our CEO and founder who beneficially owns 42.5% of our outstanding common stock, has operated in the oil and gas industry for over 34 years after starting his career at Exxon as a petroleum engineer. 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. During the year ended December 31, 2006, we spent approximately $129.7 million on development drilling, which represents 19% of our capital expenditures for such period. A majority of these drilling wells 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. In the last two years we have also made larger acquisitions that complemented our existing properties in our core areas. During the year ended December 31, 2006, we made acquisitions of approximately $489.1 million, or 73% of our total capital expenditures for such period. Our 2007 acquisition capital budget for oil and gas properties is $25.0 million, or 12% 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

Index to Financial Statements

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 17 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, 2006, we had an inventory of 601 developed enhancement projects requiring total estimated capital expenditures of $26.4 million.

Expand CO₂ enhanced oil recovery activities. We have accumulated interests in 54 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 began CO₂ injection in our North Perryton Unit in December 2006 and plan to begin CO₂ injection in our NW Camrick Unit in 2008. To support our existing CO₂ tertiary recovery projects, we currently inject approximately 33 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, a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline and recently purchased a 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and Southwestern Kansas that will enhance our CO₂ plans in this area.

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 $10.0 million, or approximately 5% of our 2007 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, 2006, we operated properties comprising approximately 83% 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 proved developed production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of September 30, 2007, we had swaps in place for approximately 72% and 15% of our most recent internally estimated proved developed gas production for 2007 and 2008, respectively. We also had swaps in place for approximately 70% of our most recent internally estimated proved developed oil production for 2007 through 2011. 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 $21.4 million, $68.3 million and $4.2 million for the years ended December 31, 2004, 2005 and 2006, respectively, through a period of increasing commodity prices.

Index to Financial Statements

Significant developments, financings and acquisitions

Below is a summary of our material financings and acquisitions that have occurred in the last twelve months:

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, and may or may not complete it 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.

Private equity sale. On September 29, 2006, we closed the sale of 280,000 shares of our common stock (representing 31.9% of our outstanding common stock) to Chesapeake Energy Corporation, of which 102,000 primary shares were sold by us for an aggregate purchase price of $102.0 million and 178,000 secondary shares were sold by our selling stockholders. Proceeds from the sale to us after commissions and expenses were approximately $100.9 million. The net proceeds we received were used to reduce outstanding indebtedness under our revolving credit facility, and subsequently available borrowings were used for general corporate and working capital purposes and acquisitions of oil and gas properties, including our acquisition of Calumet.

Calumet acquisition. On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates for a cash price of $500.0 million. The transaction was financed through an increase in our existing credit agreement to $750 million as well as from the net proceeds of approximately $100.9 million received by us in connection with the private equity sale to Chesapeake Energy Corporation on September 29, 2006. Based on a reserve report prepared by Lee Keeling & Associates, Inc., as of September 30, 2006, estimated provide reserves attributable to the acquisition are approximately 347 Bcfe, which equates to an acquisition price of $1.44 per Mcfe. The reserves are 96% oil and 67% proved developed with a PV-10 of $536.0 million. Daily production from the reserves averaged 28 MMcfe per day during September 2006. Two of Calumet’s largest properties, the North Burbank Unit and the Fox Deese Springer Unit, provide significant drilling and enhanced oil recovery opportunities.

Restated Credit Agreement. On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement is secured by our oil and gas properties and matures on October 31, 2010. Availability under our Credit Agreement is subject to a borrowing base of $500.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. Effective November 1, 2007, the borrowing base was increased to $525.0 million. Our Credit Agreement contains various financial and other covenants. See “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources” for additional information.

Green Country Supply Acquisition. On April 16, 2007, we acquired all of the outstanding shares of stock of Green Country Supply, Inc. or GCS for an aggregate purchase price of $25.0 million, subject to certain post-closing price adjustments. Approximately $5.0 million of the purchase price was deposited into escrow as security for certain potential working capital, environmental

and employment adjustments. GCS was owned by the former shareholders of Calumet Oil

Index to Financial Statements

Company and provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming. During the year ended December 31, 2006, based on unaudited information provided to us by GCS, its total sales were approximately $43.3 million, including sales of $10.0 million to Calumet.

Oklahoma Ethanol L.L.C. In April 2007, Oklahoma Ethanol L.L.C. agreed to construct and operate an ethanol plant in Blackwell, Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of denatured ethanol annually. The ethanol plant is estimated to also generate approximately 8 MMcf per day of CO₂ per year and 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 for this joint venture are estimated to be between $115 million and $125 million, with Chaparral currently having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $69 million to $75 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 construction to commence in 2008 with completion in 2010, and that our equity contribution will be approximately $30 million to $33 million.

Risk factors

Our business and our business strategy are subject to a number of material risks described in “Risk factors” beginning on page 23, including:

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volatility of oil and gas prices;

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writedowns of the carrying values of our properties;

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risks inherent in estimating reserves;

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our leverage and ability to borrow future funds;

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competition for acquisitions;

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demand for oil field equipment, services and qualified personnel;

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changes in laws and regulations; and

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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.

Index to Financial Statements

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,

Nine

Months

Ended
September 30,

2007

2002

2003

2004

2005

2006

Ratio of earnings to fixed charges

3.1x

5.3x

5.4x

2.3x

1.8x

1.0x

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.

Index to Financial Statements

The exchange offer

On January 18, 2007, 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 reasonable best 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

8⁷/8% Senior Notes due February 1, 2017, which were issued on January 18, 2007.

New Notes

8⁷/8% Senior Notes due February 1, 2017. 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 , 2008, 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:

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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

Index to Financial Statements

other documents required by the letter of transmittal, to Wells Fargo Bank, National Association, as registrar and exchange agent, at the address listed under the caption “The exchange offer—Exchange agent”; or

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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

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the old notes are not immediately available,

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

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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.

Index to Financial Statements

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 , 2008. 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 exchange 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:

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

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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;

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you are not our affiliate; and

•

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

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

Index to Financial Statements

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: (612) 667-6282

By Mail/Overnight Delivery/Hand: Wells Fargo Bank, National Association, Corporate Trust Operations, MAC N9303-121, Sixth & Marquette Avenue, Minneapolis, MN 55479

Confirm By Telephone: (800) 344-5128

Index to Financial Statements

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 8⁷/ 8% Senior Notes due 2017.

Maturity date

February 1, 2017.

Interest payment dates

Interest on the new notes will accrue at the rate of 8⁷/8% per year and will be payable semi–annually on February 1 and August 1 of each year, beginning August 1, 2007.

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., Pointe Vista Development, L.L.C. and Chaparral Biofuels, L.L.C. will be unrestricted subsidiaries 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, including our 8¹ /2% Senior Notes due 2015;

•

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, including the guarantees of our 8¹/2% Senior Notes due 2015;

•

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

Index to Financial Statements

•

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 September 30, 2007, the notes were effectively subordinated to $430.0 million of senior secured debt, and we would have had $68.3 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 February 1, 2012. We may also redeem up to 35% of the aggregate principal amount of the notes using the proceeds from certain equity offerings completed before February 1, 2010. In addition, we may redeem the notes, in whole or in part, at any time prior to February 1, 2012 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.

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

Index to Financial Statements

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 46 and the “Unaudited pro forma financial data” beginning on page 41 of this prospectus. The historical consolidated financial data for each of the three fiscal years ended December 31, 2006 (except for balance sheet data as of December 31, 2004) were derived from our audited annual financial statements included in this prospectus.

The data for the nine months ended September 30, 2006 and 2007 were derived from our unaudited interim financial statements also appearing in this prospectus. In the opinion of management, this nine-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 summary pro forma financial data for the fiscal year ended December 31, 2006 gives effect to the transactions described on page 41 of this prospectus.

Index to Financial Statements


	Year ended December 31,
	Historical									Pro forma
(Dollars in thousands)	2004			2005			2006			2006 (unaudited)

Operating results data:
Revenues
Oil and gas sales	$	113,546		$	201,410		$	249,180		$	339,339
Loss on oil and gas hedging activities		(21,350	)		(68,324	)		(4,166	)		(4,166	)

Total revenues		92,196			133,086			245,014			335,173

Costs and expenses
Lease operating		26,928			42,147			71,663			97,600
Production taxes		8,272			14,626			18,710			25,594
Depreciation, depletion and amortization		17,533			31,423			52,299			69,711
General and administrative		5,985			9,808			14,659			16,454

Total costs and expenses		58,718			98,004			157,331			209,359

Operating income		33,478			35,082			87,683			125,814

Non-operating income (expense)
Interest expense		(6,162	)		(15,588	)		(45,246	)		(75,774	)
Non-hedge derivative losses		—			—			(4,677	)		(8,497	)
Other income		279			665			792			2,611

Net non-operating expense		(5,883	)		(14,923	)		(49,131	)		(81,660	)

Income before income taxes and minority interest		27,595			20,159			38,552			44,154
Income tax expense		9,880			7,309			14,817			16,970
Minority interest		—			—			(71	)		(71	)

Net income	$	17,715		$	12,850		$	23,806		$	27,255

Cash flow data:
Net cash provided by operating activities	$	46,870		$	55,744		$	89,198
Net cash used in investing activities		(92,141	)		(325,068	)		(703,848	)
Net cash provided by financing activities		54,061			257,080			621,855

	As of December 31,
	Historical
	2004			2005			2006

Financial position data:
Cash and cash equivalents	$	13,842		$	1,598		$	8,803
Total assets		308,827			647,379			1,331,435
Total debt		176,622			446,544			976,272
Retained earnings		48,692			58,126			80,883
Accumulated other comprehensive loss, net of income taxes		(12,107	)		(47,967	)		(3,946	)
Total equity		36,586			10,167			177,864

Index to Financial Statements


	Nine months ended September 30,
(Dollars in thousands)	2006 (unaudited)			2007 (unaudited)

Operating results data:
Revenue
Oil and gas sales	$	181,892		$	256,873
Loss on oil and gas hedging activities		(5,412	)		(10,784	)
Service company sales		—			13,419

Total revenues		176,480			259,508

Costs and expenses
Lease operating		46,951			77,835
Production taxes		13,869			18,265
Depreciation, depletion and amortization		35,163			63,385
General and administrative		9,660			15,911
Service company expenses		—			11,626

Total costs and expenses		105,643			187,022

Operating income		70,837			72,486

Non-operating income (expense)
Interest expense		(28,993	)		(65,021	)
Non-hedge derivative losses		(4,634	)		(6,228	)
Other income		556			815

Net non-operating expenses		(33,071	)		(70,434	)

Income before income taxes		37,766			2,052
Income tax expense		14,520			764
Minority interest		(71	)		—

Net income	$	23,317		$	1,288

Cash flow data:
Net cash provided by operating activities	$	72,160		$	79,807
Net cash used in investing activities		(165,211	)		(184,198	)
Net cash provided by financing activities		194,178			110,609

	As of September 30, 2007
	(unaudited)

Financial position data:
Cash and cash equivalents	$	15,021
Total assets		1,472,209
Total debt		1,095,331
Retained earnings		82,171
Accumulated other comprehensive loss, net of income taxes		(25,175	)
Total equity		157,923

Index to Financial Statements

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, 2006 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, 2006 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	$	1,087.4	$	254.2	$	833.2
Permian Basin		170.6		64.3		106.3
Ark-La-Tex		47.9		16.6		31.3
North Texas		38.4		15.1		23.3
Rocky Mountains		56.7		18.3		38.4
Gulf Coast		93.1		43.4		49.7
Total	$	1,494.1	$	411.9	$	1,082.2

Index to Financial Statements

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, 2004, 2005 and 2006), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2004, 2005 and 2006 were prepared by Cawley, Gillespie and Associates, Inc. (44% of PV-10 value in 2006) and Lee Keeling & Associates, Inc. (41% of PV-10 value in 2006), both independent petroleum engineering firms, and our engineering staff (15% of PV-10 value in 2006).

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,
	2004	2005		2006


Proved Reserves
Oil (MBbl)	28,585		33,913		88,378
Natural gas (MMcf)	263,620		414,384		375,311
Natural gas equivalent (MMcfe)	435,130		617,862		905,579
Proved developed reserve percentage	67%		69%		69%
PV-10 value (in thousands)	$775,116	$	1,602,610	$	1,494,063
Estimated reserve life (in years)(1)	22.9		24.4		28.0

Cost incurred (in thousands):
Property acquisition costs
Proved properties(2)	$ 28,483	$	216,742	$	484,404
Unproved properties	2,063		5,543		4,731

Total acquisition costs	30,546		222,285		489,135
Development costs	62,371		103,479		170,987
Exploration costs	3,114		7,274		7,015

Total	$ 96,031	$	333,038	$	667,137

Annual reserve replacement ratio(3)	794%		822%		991%
Three-year average fully developed FD&A cost ($/Mcfe)(4)		$	1.82	$	2.37

(1)

Calculated by dividing net proved reserves by net production volumes for the year indicated

(2)

Includes $152,945 and $464,860 of costs related to the acquisitions of CEI Bristol and Calumet in 2005 and 2006, respectively.

(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. The values for these reserve additions are derived directly from the proved reserves table located in Note 17 of the notes to our consolidated financial statements. In calculating reserve replacement, we do not use unproved reserve quantities. Management uses the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow reserves, thereby providing some information of the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. The reserve replacement ratio is comprised of the following:


	Year ended December 31,
	2004		2005				2006
	Reserves replaced	Percent of total	Reserves replaced		Percent of total		Reserves replaced		Percent of total

Purchases	328%	41.3%	683%		83.1%		1,093%		110.3%
Extensions and discoveries	179%	22.5%	89%		10.8%		52%		5.3%
Revisions	77%	9.7%	(30%	)	(3.6%	)	(174%	)	(17.6%	)
Improved recoveries	210%	26.5%	80%		9.7%		20%		2.0%

Total	794%	100.0%	822%		100.0%		991%		100.0%

Index to Financial Statements

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,						Nine months ended September 30,
	2004		2005		2006		2006		2007


Net production volumes
Oil (MBbls)		1,173		1,449		1,906		1,262		2,507
Natural gas (MMcf)		11,923		16,660		20,949		15,592		15,246

Combined (MMcfe)		18,961		25,354		32,385		23,164		30,288

Oil and gas sales ($ in thousands)(1)
Oil	$	47,537	$	77,899	$	117,504	$	80,462	$	160,059
Natural gas		66,009		123,511		131,676		101,430		96,814

Total	$	113,546	$	201,410	$	249,180	$	181,892	$	256,873

Oil average sales price (per Bbl)
Price excluding hedges	$	40.53	$	53.76	$	61.65	$	63.76	$	63.84
Price including hedges	$	29.16	$	36.43	$	47.32	$	44.46	$	58.05

Natural gas average sales price (per Mcf)
Price excluding hedges	$	5.54	$	7.41	$	6.29	$	6.51	$	6.35
Price including hedges	$	4.86	$	4.82	$	7.39	$	7.72	$	6.60

Average production cost and production taxes (per Mcfe)
Average production cost(2)	$	1.42	$	1.66	$	2.21	$	2.03	$	2.57
Average production taxes(3)	$	0.44	$	0.58	$	0.58	$	0.60	$	0.60

(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.

Index to Financial Statements

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.

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.”

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:

Index to Financial Statements

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.

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:

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 our financial condition, results of operations and reserves. If the oil and natural gas industry

Index to Financial Statements

experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our senior secured credit facility, our 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, 2006 PV-10 value uses realized prices based on a Henry Hub spot price of $5.64 per MMBtu for natural gas and a WTI Cushing spot price of $61.06 per Bbl for oil.

Index to Financial Statements

A significant portion of total proved reserves as of December 31, 2006 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2006, 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.

Some of our reserves are subject to tertiary recovery methods and the failure of these methods may have a material adverse affect on our financial condition, results of operations and reserves.

As of December 31, 2006, 14.8% of our proved reserves were based on tertiary recovery methods including the injection of CO₂ and polymers, a synthetic chemical. Some of these properties have not been injected with CO₂or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or in the production levels we anticipate. Our ability to develop future reserves will depend on whether we can successfully implement our planned tertiary recovery programs, and our failure to do so could have a material adverse affect on our financial condition, results of operations and reserves.

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 September 30, 2007, our total debt was $1.1 billion and our total book capitalization was $1.3 billion. Our maximum commitment amount and the borrowing base under our new Seventh Restated Credit Agreement was $500.0 million. 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:

Index to Financial Statements

If an event of default occurs under our Credit Agreement or our 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, which is $525.0 million as of November 1, 2007, and which is set by the banks semi-annually on May 1 and November 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. 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:

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.

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

Index to Financial Statements

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 reserves and production will decline over time. In addition, approximately 31% of our total estimated proved reserves (by volume) at December 31, 2006 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 historical December 31, 2006 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14.3%, 11.0% and 8.6% 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. Seismic imaging is an imaging tool used by geologists to generate an interpretation of certain geological structures, and different geologists may have materially different interpretations of the same seismic data. 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:

Index to Financial Statements

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 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:

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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.

Our use of derivative instruments 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. As of September 30, 2007, we had entered into swaps for 6,790 MMcf of our natural gas production for 2007 through 2008 at average monthly prices ranging from $7.58 to $10.15 per Mcf of natural gas. As of September 30, 2007, we had entered into swaps for 8,323 MBbl of our crude oil production for 2007 through 2011 at average monthly prices ranging from $62.92 to $68.77 per Bbl of oil. As of September 30, 2007, we had basis protection swaps for 13,460 Mcf for 2007 through 2009 at average monthly prices ranging from $0.79 to $1.17 per Mcf. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2007 was a liability of approximately $49.3 million. Derivative instruments expose us to risk of financial loss in some circumstances, including when:

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, 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, Accounting for Derivative Instruments and Hedging Activities, 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 2004, 2005, or 2006.

Index to Financial Statements

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 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.

We may not be able to successfully integrate Calumet’s operations with our operations, and the failure to do so could have a material adverse effect on our business, financial condition and results of operations.

Integration of the previously independent company is a complex, time consuming and costly process. Failure to timely and successfully integrate Calumet may have a material adverse effect on our business, financial condition and results of operations. The difficulties of combining Calumet present challenges to our management including:

The combined company is also exposed to risks that are commonly associated with transactions similar to the acquisition, such as unanticipated liabilities and costs, some of which may be

Index to Financial Statements

material, and diversion of management’s attention. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all.

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 senior credit agreement, the indenture governing our outstanding Senior Notes, or our 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:

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.

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 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:

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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.

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:

All of the outstanding borrowings under the Credit Agreement as of September 30, 2007 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 $500.0 million, equal to our borrowing base at September 30, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.0 million.

The concentration of accounts for our oil and gas sales, joint interest billings or derivative instruments 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. 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 derivative instruments 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 derivative arrangements, we may be exposed to greater credit risk in the future.

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

Index to Financial Statements

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:

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:

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.

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 and holders of our outstanding 8¹/2% Senior 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. Further, we will be contractually restricted under the terms of our Credit Agreement from repurchasing all of the notes tendered upon a change of control. Accordingly, we may be unable to satisfy our obligations to purchase the notes unless we are able to refinance or obtain waivers under our

Index to Financial Statements

Credit Agreement. Our failure to purchase the notes as required under the indenture would result in a default under the indenture and a cross-default under our Credit Agreement, each of which could have material adverse consequences for us and the holders of the notes. In addition, the Credit Agreement provides that a change of control is a default that permits lenders to accelerate the maturity of borrowings thereunder. See “Description of the notes—Change of control.”

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

As of September 30, 2007, we had approximately $430.0 million of secured indebtedness outstanding under our Credit Agreement and $17.9 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 are not and may not in the future be guaranteed by all of our subsidiaries, 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 structurally 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 structurally subordinated to all those claims. As of the closing date, all of our existing wholly- owned subsidiaries will be guarantors of the notes, but the notes will not be guaranteed by Oklahoma Ethanol L.L.C., which is a less than wholly-owned subsidiary, or Pointe Vista Development, L.L.C. or Chaparral Biofuels, L.L.C., which are unrestricted subsidiaries.

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 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.”

Index to Financial Statements

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 indentures governing the 8¹/2% Senior Notes and the notes offered hereby. 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 indentures governing the 8¹/2% Senior Notes and the notes offered hereby 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 notes.”

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

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.

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

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In addition, our Credit Agreement and the indenture governing our 8¹/2% Senior Notes 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, the 8¹/2% Senior Notes and/or the notes offered hereby. 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.

Index to Financial Statements

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

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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.

Index to Financial Statements

The following unaudited table sets forth our capitalization as of September 30, 2007 and should be read together with our financial statements and the accompanying notes included in this prospectus.

Index to Financial Statements

The following unaudited pro forma condensed financial information for the fiscal year ended December 31, 2006 gives effect to the following transactions:

The following unaudited pro forma financial information and explanatory notes assume the transactions all occurred on January 1, 2006. The unaudited pro forma combined financial information shows the impact of the acquisition all of the outstanding capital stock of Calumet Oil Company, all of the limited partnership interests of JMG Oil & Gas, LP and all of the membership interests of J.M. Graves L.L.C. under the purchase method of accounting.

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, 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.

Index to Financial Statements

The accompanying unaudited pro forma statement of operations of Chaparral for the year ended December 31, 2006 has been prepared to give effect to the acquisition of Calumet, including the increased borrowings under the restated credit agreement, the application of proceeds of the private equity sale on September 29, 2006, and the issuance of our 8⁷/8% Senior Notes issued on January 18, 2007 as if the transactions occurred on January 1, 2006.

Chaparral uses the full cost method of accounting for its oil and gas producing activities while Calumet used 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.

The unaudited pro forma statements of operations include the following adjustments:

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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, 2006 were derived from our audited consolidated financial statements. The data for the nine months ended September 30, 2006 and 2007 were derived from our unaudited interim financial statements appearing in this prospectus. In the opinion of management, this nine-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.

Index to Financial Statements

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 report.

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.

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, Ark-La-Tex, 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, 2006, we had estimated proved reserves of 906 Bcfe, with a PV-10 value of $1.5 billion. Our reserves were 69% proved developed and 59% crude oil. Beginning in April 2007, we expanded our operations to include oil and gas services through the acquisition of Green Country Supply, Inc. (“GCS”). GCS provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

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. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and gas production affect our:

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 14.3%, 11.0% and 8.6% 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.

Index to Financial Statements

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

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.

The following are material events that have impacted the results of operations or liquidity discussed below, or are expected to impact these items in future periods:

Index to Financial Statements

Comparison of three months ended September 30, 2007 to three months ended September 30, 2006.

Oil & Gas Revenues and Production. The following table presents information about our oil and gas sales before the effects of hedging:

Index to Financial Statements

Oil sales increased 145.4% from $27.5 million during the three months ended September 30, 2006 to $67.6 million during the same period in 2007. This increase was due to a 122.6% increase in production volumes to 926 MBbls, and a 10.3% increase in average oil prices to $72.98 per barrel. Natural gas sales revenues decreased 3.4% from $32.1 million during the three months ended September 30, 2006 to $31.0 million during the same period in 2007. This decrease was due to an 2.4% decrease in average gas prices, and a 1.1% decrease in production volumes to 5,053 MMcf. Oil production for the three months ended September 30, 2007 increased primarily due to the addition of volumes from the Calumet acquisition, our drilling program and enhancements of our existing properties. Approximately 426 MBbls of the oil production for the three months ended September 30, 2007 was related to properties acquired in the Calumet acquisition.

Commodity prices are determined by factors that are outside of our control. Historically, commodity prices have been volatile and we expect them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, storage levels, basis differentials and other factors.

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The effects of hedging on our net revenues are as follows:

Our loss from oil and gas hedging activities in the third quarter of 2007 was primarily due to losses on hedge settlements resulting from increased oil prices. As a result of lower NYMEX forward strip gas prices at September 30, 2007 compared to June 30, 2007, hedge ineffectiveness resulted in a gain of $1.0 million compared to a gain of $7.5 million in the third quarter of 2006. The decreased ineffectiveness gain during the third quarter of 2007 as compared to the same period in 2006 is also a result of significant decreases in volumes of natural gas hedged as of September 30, 2007 compared to September 30, 2006.

Index to Financial Statements

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives. The following table presents information about the effects of hedging on realized prices:

Service company revenues and operating expenses—Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $7.5 million in service company revenue in the current quarter with corresponding service company expense of $6.6 million, for a net profit of $0.9 million. There were no service company revenues or expenses during the third quarter of 2006.

Costs and Expenses. The following table presents information about our operating expenses for the third quarter of 2006 and 2007:

Lease operating expenses—Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $6.4 million of the increase were expenses attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor, and materials resulting from the sustained strength of commodity prices.

Production taxes (which include ad valorem taxes)—Increase was primarily due to a 18.5% increase in averaged realized prices, and an increase of 39.5% in production volumes compared to the same period in 2006.

Depreciation, depletion and amortization (“DD&A”)—Increase was primarily due to increase in DD&A on oil and gas properties of $9.8 million. For oil and gas properties, $5.8 million of the increase was due to higher production volumes and $4.0 million was due to an increase in the

Index to Financial Statements

DD&A rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production increased $0.52 to $1.93 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. We also recognized deferred compensation expense of $0.7 million related to our phantom unit plan in the third quarter of 2007 due to continued strength of oil commodity prices. G&A expense also includes $0.1 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $2.8 million in the third quarter of 2007 and $2.1 million in the same period of 2006 capitalized as part of our exploration and development activities.

Interest Expense. Interest expense increased during the third quarter of 2007 by $12.4 million, or 119.9%, compared to the same period in 2006 primarily as a result of increased levels of borrowings including the issuance of our 8⁷/8 % Senior Notes due 2017, and higher interest rates. Approximately $11.1 million of the increase is due to our increased levels of borrowings and $1.3 million is due to higher interest rates.

Non-hedge derivative losses. Non-hedge derivative losses were $2.4 million during the three months ended September 30, 2007 and are comprised of losses of $1.6 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges and $0.8 million related to natural gas basis differential swaps. Non-hedge derivative losses were $4.5 million during the three months ended September 30, 2006 and are comprised of losses of $1.8 million on natural gas basis differential swaps and $2.7 million on non-qualified derivative contracts.

Comparison of nine months ended September 30, 2007 to nine months ended September 30, 2006.

Revenues and Production. The following table presents information about our oil and gas sales before the effects of hedging:

Index to Financial Statements

Oil sales increased 98.9% from $80.5 million during the nine months ended September 30, 2006 to $160.1 million during the same period in 2007. This increase was due to an 98.7% increase in production volumes to 2,507 MBbls and a 0.1% increase in average oil prices to $63.84 per barrel. Natural gas sales revenues decreased 4.6% from $101.4 million during the nine months ended September 30, 2006 to $96.8 million during the same period in 2007. This decrease was due to a 2.2% decline in production volumes to 15,246 MMcf and a 2.5% decrease in average gas prices. Oil production for the nine months ended September 30, 2007 increased primarily due to the addition of volumes from the Calumet acquisition, our drilling program and enhancements of our existing properties, partially offset by decreased production on existing producing properties due to increased seasonal weather disruptions during the first quarter of 2007. Approximately 1,149 MBbls of the oil production for the nine months ended September 30, 2007 was related to properties acquired in the Calumet acquisition. Gas production for the nine months ended September 30, 2007 decreased primarily due to the recognition of a favorable settlement of a disputed ownership interest that resulted in the one-time recognition of 393 MMcf for production from May 2005 to April 2006 during the nine months ended September 30, 2006.

Index to Financial Statements

Our loss from oil and gas hedging activities during the first nine months of 2007 was primarily due to losses on hedge settlements due to increased oil prices. As a result of higher NYMEX forward strip gas prices at September 30, 2007 compared to December 31, 2006, hedge ineffectiveness resulted in a loss of $3.1 million compared to a gain of $17.6 million during the same period in 2006. Settlements on our oil and gas contracts decreased $15.3 million primarily due to the settlement of higher overall hedge positions during the nine months ended September 30, 2007 as compared to the same period in 2006.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives. The following table presents information about the effects of hedging on realized prices:

Service company revenues and operating expenses—Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $13.4 million in service company revenue during the second and third quarters with corresponding service company expense of $11.6 million, for a net profit of $1.8 million. There were no service company revenues or expenses during the first three quarters of 2006 or in the first quarter of 2007.

Costs and Expenses. The following table presents information about our operating expenses for the first nine months of 2006 and 2007:

Lease operating expenses—Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $19.8 million of the increase were expenses attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor, and

Index to Financial Statements

materials resulting from the sustained strength of commodity prices. Included in these figures are $5.4 million of costs associated with workovers in the first three quarters of 2007 compared to $6.0 million in the same period of 2006.

Production taxes (which include ad valorem taxes)—Increase was primarily due to 8.0% higher averaged realized prices, and an increase of 30.8% in production volumes compared to the same period in 2006.

Depreciation, depletion and amortization (“DD&A”)—Increase was primarily due to increase in DD&A on oil and gas properties of $26.4 million. For oil and gas properties, $13.7 million of the increase was due to higher production volumes and $12.8 million due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production increased $0.55 to $1.92 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. In addition, we increased our compensation plan, including an increase in our officer bonus program and decreased the vesting period related to the phantom unit plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.4 million of the increase was due to the revision in the phantom unit plan. G&A expense also includes $0.4 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $8.0 million during the first three quarters of 2007 and $6.3 million in the same period of 2006 capitalized as part of our exploration and development activities.

Interest Expense. Interest expense increased during the first nine months of 2007 by $36.0 million, or 124.3%, compared to the same period in 2006 primarily as a result of increased levels of borrowings including the issuance of our 8⁷/8% Senior Notes due 2017, and higher interest rates paid. Approximately $32.5 million of the increase is due to our increased levels of borrowings and $3.5 million is due to higher interest rates paid.

Non-hedge derivative losses. Non-hedge derivative losses were $6.2 million during the nine months ended September 30, 2007 and are comprised of losses of $7.4 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, partially offset by net gains of $1.2 million related to natural gas basis differential swaps. Non-hedge derivative losses were $4.6 million during the nine months ended September 30, 2006 and are comprised of losses of $1.9 million on natural gas basis differential swaps and $2.7 million on non-qualified derivative contracts.

Index to Financial Statements

Revenues and Production. The following table presents information about our oil and gas sales before the effects of hedging:

Oil sales increased 50.8% from $77.9 million to $117.5 million during the year ended December 31, 2006. This increase was due to a 31.5% increase in production volumes to 1,906 MBbls and a 14.7% increase in average oil prices to $61.65 per barrel. Natural gas sales revenues increased 6.6% from $123.5 million for the year ended December 31, 2005 to $131.7 million for the year ended December 31, 2006. This increase was due to a 25.7% increase in production volumes to 20,949 Mmcf, partially offset by a 15.1% decrease in average gas prices to $6.29 per Mcf. Oil and gas production for the year ended December 31, 2006 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties. Approximately 1,655 MMcfe of the increase was due to the Calumet acquisition.

Index to Financial Statements

The effects of hedging on our net revenues for the years ended December 31, 2005 and 2006 are as follows:

Our loss from oil and gas hedging settlements in 2006 decreased $30.7 million due to improved hedge positions in relation to commodity prices from 2006 compared to 2005. Additionally as a result of lower NYMEX forward strip gas prices at December 31, 2006 compared to December 31, 2005, hedge ineffectiveness resulted in a gain of $18.8 million in 2006 compared to a loss of $14.7 million in 2005.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts that qualify for hedge accounting. The following table presents information about the effects of hedging on realized prices:

Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2005 and 2006:

Lease operating expenses—Increase was generally due to increases in the number of net producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $5.1 million of the increase were expenses attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor, and materials resulting from the sustained strength of commodity prices. Included in the figures are $9.5 million of costs associated with workovers in 2006 compared to $4.5 million in 2005.

Index to Financial Statements

Production taxes (which include ad valorem taxes)—Increase was due primarily to a 28% increase in production volumes.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $19.4 million. For oil and gas properties, $10.2 million of the increase was due to higher production volumes in 2006 and $9.2 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 on oil and gas properties increased by $0.36 to $1.45 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. Approximately $0.9 million, or $0.03 per mcfe, of the increase related to due diligence costs incurred in connection with the Calumet acquisition and other Calumet related general and administrative expenses. Approximately $0.5 million, or $0.02 per mcfe, of the increase was due to costs incurred in connection with a postponed initial public offering. G&A expense is net of $8.3 million in 2006 and $6.2 million in 2005 capitalized as part of our exploration and development activities.

Interest expense. Interest expense increased by $29.7 million, or 190%, compared to 2005, primarily as a result of increased levels of borrowings and higher interest rates paid. Approximately $25.9 million of the increase is due to the issuance of the 8¹/2% Senior Notes on December 1, 2005.

Non-hedge derivative losses. Non-hedge derivative losses were $4.7 million for the year ended December 31, 2006 and are comprised of losses of $3.8 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, and $0.9 million of losses related to natural gas basis differential swaps. There were no non-hedge derivatives in 2005.

Revenues and Production. The following table presents information about our oil and gas sales before the effects of hedging:

Index to Financial Statements

Oil sales increased 63.9% from $47.5 million to $77.9 million during the year ended December 31, 2005. This increase was due to a 23.5% increase in production volumes to 1,449 MBbls and a 32.6% increase in average oil prices to $53.76 per barrel. Natural gas sales revenues increased 87.1% from $66.0 million for the year ended December 31, 2004 to $123.5 million for the year ended December 31, 2005. This increase was due to a 39.7% increase in production volumes to 16,660 Mmcf and a 33.8% increase in average gas prices to $7.41 per Mcf. Oil and gas production for the year ended December 31, 2005 increased due primarily to the addition of volumes from acquisitions, our expanded drilling program and enhancements of our existing properties.

The effects of hedging on our net revenues for the years ended December 31, 2004 and 2005 are as follows:

Our loss from oil and gas hedging settlements in 2005 increased $32.8 million due to higher commodity prices in relation to our hedge position from 2005 compared to 2004. Additionally as a result of higher NYMEX forward strip gas prices at December 31, 2005 compared to December 31, 2004, hedge ineffectiveness resulted in a loss of $14.7 million compared to $0.6 million in 2004.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives. The following table presents information about the effects of hedging on realized prices:

Index to Financial Statements

Costs and Expenses.—The following table presents information about our operating expenses for each of the years ended December 31, 2004 and 2005:

Lease operating expenses—Increase was due primarily to increases in the number of net producing wells and higher oilfield service costs. Included in the figures are $4.5 million of costs associated with workovers in 2005 compared to $2.4 million in 2004.

Production taxes (which include ad valorem taxes)—Increase was due primarily to a 34% increase in production volumes and average realized prices being 33% higher for the year ended December 31, 2005 compared to the same period in 2004.

Depreciation, depletion and amortization—Increase was due primarily 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 on oil and gas properties increased by $0.32 to $1.09 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. 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 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.

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 8¹/2% 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 that was subsequently refinanced with the net proceeds from the 8¹/2% Senior Notes.

Overview. Our primary sources of liquidity are cash generated from our operations, issuance of equity and our revolving credit line. At September 30, 2007, we had approximately $15.0 million of cash and cash equivalents and $68.3 million of availability under our revolving credit line with a borrowing base of $500.0 million. The indentures governing our 8¹/2% Senior Notes and 8⁷/8% Senior Notes also contain restrictions as to the amount we may borrow under our credit

Index to Financial Statements

agreement. As of September 30, 2007, we had approximately $45.3 million of availability under our credit agreement pursuant to the restrictions contained in the indentures. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months. Our 2008 capital expenditures budget assumes we receive proceeds from an issuance of our equity during 2008. If we are unable to consummate an offering of our equity, we may be required to adjust our planned capital expenditures during 2008.

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, 2006, we incurred actual costs as summarized by area in the following table:

Index to Financial Statements

In addition to the capital expenditures for oil and gas properties, we spent approximately $12.7 million for the acquisition and construction of new office and administrative facilities and equipment during 2006.

Our actual costs incurred for the year ended December 31, 2006 and nine months ended September 30, 2007 and our current 2007 budgeted capital expenditures for oil and gas properties are detailed in the table below:

Our 2007 budgeted development and exploratory drilling and tertiary recovery capital expenditures summarized by area are detailed in the table below:

A majority of our capital expenditure budget for development drilling in 2007 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.

While we have not finalized our capital expenditure budget for 2008, we currently expect our capital expenditures for oil and gas properties in 2008 to be consistent with our budgeted amounts for 2007. We continually evaluate our capital needs and compare them to our estimated funds available. Our actual expenditures 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.

Index to Financial Statements

Cash provided from operating activities. Substantially all of our cash flow from operating activities is from the production and sale of oil and gas adjusted 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, 2006, the net cash provided from operations was approximately 38% of our net cash used in investing activities excluding the Calumet acquisition. For the year ended December 31, 2006, cash flow from operating activities increased by 60% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue and reduced settlement losses on hedging activities partially offset by higher operating expense.

For the nine months ended September 30, 2007, net cash provided from operations increased 10.6% from the same period in the prior year and provided approximately 43.3% 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 and interest expenses.

Our current credit facility. On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement is secured by our oil and gas properties and matures on October 31, 2010. Obligations under the Credit Agreement are also secured by pledges by us and each of the borrowers of equity interests in other subsidiaries owned by us and them, excluding specified entities. Availability under our Credit Agreement is currently subject to a borrowing base of $525.0 million, which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. The indentures governing our 8¹/2% Senior Notes and 8⁷/8% Senior Notes also contain restrictions as to the amount we may borrow under our credit agreement. As of September 30, 2007, the availability under our credit agreement pursuant to the restrictions contained in the indentures exceeded the allowable borrowing base.

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.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2007, 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 2.50% depending on the utilization percentage of the conforming borrowing base. At September 30, 2007, the LIBOR rate was 5.54%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 1.82% resulting in an effective interest rate of 7.36% 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.

Index to Financial Statements

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 1.00% depending on the utilization percentage of the borrowing base. At September 30, 2007, the applicable rate was 8.25% and the applicable margin was 0.25% resulting in an effective interest rate of 8.50% 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 0.50% 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, among other things, to:

The Credit Agreement requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Credit Agreement, of not greater than:

Index to Financial Statements

As of March 31, 2007, we did not meet the 5.00 to 1.0 Consolidated Total Debt to Consolidated EBITDAX ratio as required by the Credit Agreement. Effective May 11, 2007, the Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For purposes of the amended ratio, Consolidated Senior Total Debt consists of all outstanding loans under the Credit Agreement, letters of credit and all obligations under capital leases, as defined in the First Amendment to our Credit Agreement. The amended Credit Agreement requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2007.

Index to Financial Statements

Our Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0. 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 compliance 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 a useful 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, 2006 and September 30, 2007, our current ratio as computed using generally accepted accounting principles was 0.88 and 0.99, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.15 and 1.76, 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:

Our 8¹/2% Senior Notes due 2015. On December 1, 2005, we issued $325.0 million aggregate principal amount of 8¹/2% Senior Notes maturing on December 1, 2015. The 8¹/2% 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 8¹/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries, as defined in the indenture.

On and after December 1, 2010, we may redeem some or all of the 8¹/2% 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 8¹/2% Senior Notes from the proceeds, so long as:

Index to Financial Statements

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 8¹/2% Senior Notes. The provisions of the indenture limit our and our restricted subsidiaries’ ability to, among other things:

If we experience a change of control (as defined in the indenture governing the 8¹/2% Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the 8¹/2% Senior Notes the opportunity to sell to us their 8¹/2% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. Once complete, the exchange offer must remain open for at least 20 business days. If we fail to complete the exchange offer within 270 days after the closing date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

During September 2007, we determined that the exchange offer would not be completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $0.2 million during the three months ended September 30, 2007.

Alternative capital resources. We have historically used cash flow from operations, debt financing and private issuance of common stock as our primary sources of capital. In the future we may use additional sources such as asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain

Index to Financial Statements

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, 2006:

We entered into an agreement to build a natural gas pipeline, a CO₂ pipeline and compression facilities at an ethanol plant expected to be constructed and operational in early 2008. The construction of these pipelines and facilities and the related costs are contingent on certain events and are currently estimated to be a minimum of $2.2 million. We also have a long-term contract to purchase all of the CO₂ manufactured at the ethanol plant, if built. Based on estimated plant capacity, it is estimated that we will purchase approximately 4.2 Mmcf per day at variable contract prices over the ten-year contract term with the possibility of renewal.

We have two additional long-term contracts that require us to purchase CO₂ for tertiary recovery projects. Under one contract we may purchase a variable amount of CO₂, up to 20.0 MMcf per day through July 1, 2010. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 16.0 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, which is consistent with our current level. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

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

Index to Financial Statements

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.

Derivative Instruments. Certain of 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 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 “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 stockholders’ equity. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. The ineffective portion of the hedge gain or loss is reported in the “Loss on oil and gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment are marked to their period end market values with changes reported in earnings, and our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments.

Our proved reserve information included in this report 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

Index to Financial Statements

approximately 85% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2006 and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

In accordance with Statement on Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, we record a liability for the discounted fair value of an asset retirement obligation 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,

Index to Financial Statements

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 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.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company will adopt SFAS No. 157 as of January 1, 2008 and is currently evaluating the impact, if any, that SFAS No. 157 will have on its consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company will adopt SFAS No. 159 as of January 1, 2008 and is currently evaluating the impact, if any, that SFAS No. 159 will have on its consolidated financial statements.

Index to Financial Statements

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.

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, 2006 production, our gross revenues from oil and gas sales would change approximately $2.1 million for each $0.10 change in gas prices and $1.9 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into swap agreements. For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price 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.

We also use derivative financial instruments to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for gas from a specified delivery point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

In anticipation of the acquisition of Calumet, we entered into additional crude oil swaps in September and October 2006 to provide protection against a decline in the price of oil from the date of entering into a Securities Purchase Agreement and the close of the transaction on October 31, 2006. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses. Also, as a result of the acquisition, Chaparral assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges.

Index to Financial Statements

Our outstanding oil and natural gas derivative instruments as of September 30, 2007 are summarized below:

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 30, 2007 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 $500.0 million, equal to our borrowing base at September 30, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.0 million.

Index to Financial Statements

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 additional areas of Ark-La-Tex, North Texas, the Gulf Coast and the Rocky Mountains. On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for a cash purchase price of approximately $500.0 million. Calumet owned properties are located principally in Oklahoma and Texas, areas which are located in our existing core areas of operations. As of December 31, 2006, estimated proved reserves attributable to the acquisition were approximately 346 Bcfe. Calumet’s proved reserves have a 33.8 year reserve life as of December 31, 2006 (calculated as December 31, 2006 reserves of 345,786 MMcfe divided by year ended December 31, 2006 production of 10,220 MMcfe), have relatively low production decline rates averaging 5.6% from 2008 - 2010 and are approximately 96% oil. In addition to increasing our average net daily production, many of the acquired properties have significant drilling and enhanced oil recovery opportunities, as further discussed in the “Properties” section beginning on page 77.

As of December 31, 2006, we had estimated proved reserves of 906 Bcfe (69% proved developed and 59% crude oil) with a PV-10 value of approximately $1.5 billion. For the year ended December 31, 2006, our average daily production was 88.7 MMcfe and, on a pro forma basis, was 112.2 MMcfe, our estimated pro forma reserve life was 22.1 years (calculated as December 31, 2006 reserves of 905,579 MMcfe divided by year ended December 31, 2006 pro forma production of 40,953 MMcfe), and our revenues, on a pro forma basis, were $335.2 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 2003 to 2006, our proved reserves and production grew at a compounded annual growth rate of 44% and 28%, respectively. We have grown primarily through a disciplined strategy of acquiring 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 currently expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

Our costs incurred on oil and gas properties for the year ended December 31, 2006 were $667.1 million, including $129.7 million for development drilling and $489.1 million for acquisitions, of which $464.9 million were oil and gas properties acquired as part of the Calumet acquisition. Our 2007 capital expenditure budget for oil and gas properties is $212.0 million assuming an offering of our equity is consummated in 2007. The majority of our capital expenditures for developmental drilling in 2007 are 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 have also budgeted increased capital expenditures for 2007 for out carbon dioxide (CO₂) tertiary recovery projects in the Mid-Continent and Permian Basin.

Index to Financial Statements

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 2004, 2005 and 2006, our capital expenditures for acquisitions of proved properties were $28.5 million, $216.7 million and $484.4 million, respectively. These acquisition capital expenditures represented approximately 30%, 65% and 73%, respectively, of our total capital expenditures and approximately 46%, 80% and 94%, respectively, of our increases in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. In October 2006, we acquired Calumet, which added approximately 346 Bcfe of proved reserves as of December 31, 2006. Excluding the acquisition of Calumet, we spent $19.5 million on acquisitions of proved properties during 2006, representing approximately 10% of 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.

Index to Financial Statements

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 23. We have experienced a high historical drilling success rate of approximately 97% on a weighted average basis during 2004, 2005 and 2006. For the year ended December 31, 2006, we spent $133.5 million to drill 61 (48 net) operated wells and to participate in 131 (9.4 net) wells operated by others, representing 4% of our increase in reserves related to purchase of minerals in place, extensions and discoveries and improved recoveries. For 2007, we have budgeted $152.0 million to drill more than 125 operated wells and to participate in more than 140 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 42,400 square miles of 3-D seismic data, conducted four proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

Experienced management team. Mark A. Fischer, our CEO and founder who beneficially owns 42.5% of our outstanding common stock, has operated in the oil and gas industry for over 34 years after starting his career at Exxon as a petroleum engineer. 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.

Continue lower-risk development drilling program. During the year ended December 31, 2006, we spent approximately $129.7 million on development drilling, which represents 19% of our capital expenditures for such period. 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.

Index to Financial Statements

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. In the last two years we have also made larger acquisitions that complemented our existing properties in our core areas. During the year ended December 31, 2006, we made acquisitions of approximately $489.1 million, or 73% of our total capital expenditures for such period. Our 2007 acquisition capital budget for proved oil and gas properties is $25.0 million, or 12% 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 17 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, 2006, we had an inventory of 601 developed enhancement projects requiring total estimated capital expenditures of $26.4 million.

Expand CO₂ enhanced oil recovery activities. We have accumulated interests in 54 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 began CO₂ injection in our North Perryton Unit in December 2006 and plan to begin CO₂ injection in our NW Camrick Unit in 2008. To support our existing CO₂ tertiary recovery projects, we currently inject approximately 33 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, a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline, and recently purchased a 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and Southwestern Kansas that will enhance our CO₂ plans in this area.

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 $10.0 million, or approximately 5% of our 2007 capital expenditures, on exploration activities.

Index to Financial Statements

internally estimated proved developed oil production for 2007 through 2011. 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 $21.4 million, $68.3 million, and $4.2 million for the years ended December 31, 2004, 2005, and 2006, respectively, through a period of increasing commodity prices.

In April 2007, Oklahoma Ethanol L.L.C. agreed to construct and operate an ethanol plant in Blackwell, Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of denatured ethanol per year. The ethanol plant is estimated to also generate approximately 8 MMcf per day of CO₂, and 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 for this joint venture are estimated to be between $115 million and $125 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $69 million to $75 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 construction to commence in 2008 with completion in 2010, and that our equity contribution will be approximately $30 million to $33 million.

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, 78% of our 2006 production was concentrated in our two core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2006, we owned interests in 7,687 gross (2,415 net) producing wells and we operated wells representing 83% 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.

Index to Financial Statements

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2006, accounted for 76% of our proved reserves and 73% of our PV-10 value. We own an interest in 4,954 wells in the Mid-Continent, of which we operate 1,940. Our ten largest properties and 14 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2006, our net average daily production in the Mid-Continent Area was approximately 53.3 MMcfe per day, or 60% of our total net average daily production (or approximately 76.8 MMcfe per day, or 68% of our total net average daily production, on a pro forma basis). During the nine months ended September 30, 2007, our net average daily production in this area was approximately 72.3 MMcfe per day, or 65% 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 4% of our proved reserves and PV-10 value (36,840 MMcfe and $59.4 million, respectively) of our proved reserves at December 31, 2006. 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 38 active producing wells in this area that produced 857 MMcfe during the year ended December 31, 2006. Currently CO₂ injection operations are continuing in the Phase I and II areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Area from approximately 115 Bbls per day in 2001 from 11 wells to approximately 1,450 Bbls per day in November 2007 from 42 producing wells. The Phase II expansion at Camrick is currently underway. We plan to expand CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU represents 3% of our proved reserves and PV-10 value (29,778 MMcfe and $53.4 million, respectively) of our proved reserves at December 31, 2006. 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 and produced 838 MMcfe during the year ended December 31, 2006. The field was unitized in 1948 and began unitized production as a pressure maintenance operation by 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 26 active producing wells in this unit. We are scheduled to drill 16 wells in 2008.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Play accounted for 6,736 MMcfe of our proved reserves, $12.0 million of our PV-10 value as of December 31, 2006 and 556 MMcfe of our year ended December 31, 2006 production. We own approximately 6,600 acres in the Cleveland Sand Play. The Cleveland Sand occurs at 8,300 feet

Index to Financial Statements

and is considered a tight gas sand reservoir. We currently have interests in 34 Cleveland Sand producing wells, have drilled three wells in each of 2005 and 2006, have drilled five wells to date in 2007 and have scheduled an additional 12 wells in 2008. Horizontal drilling technology has been employed in the most recently drilled wells. We expect that future wells will utilize horizontal technology.

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. This unit accounted for 18,544 MMcfe of our proved reserves, $30.6 million of our PV-10 value as of December 31, 2006 and 49 MMcfe of our year ended December 31, 2006 production. 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 48 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. As of December 31, 2006, there were no proved reserves attributable to Harmon County. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling of the first four well package is complete. The Jones #1-14, commenced production at a rate of about 95 Bbls per day and is currently producing at a rate of 7 Bbls per day. The second well, the Faulks #1-12, is currently producing at a rate of 5 barrels of oil per day. The third well, the Bullington #1-29, is currently producing 7 BOPD. All three wells are producing from the Mississippi Reef zone. The last well, the CLO #1-31, tested dry and will be used as a salt water disposal well.

CO₂ Enhanced Recovery Operations—Various counties, Oklahoma and Texas. We initiated CO₂ injection in our North Perryton Unit in December 2006 and plan to initiate CO₂ injection in our NW Camrick Unit in 2008. We have in place transportation and supply agreements to provide the necessary CO₂ for these projects. Including properties recently purchased in the Calumet acquisition, we have accumulated 54 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 and recently purchased 100% interest in approximately 126 miles of pipeline located in the Panhandle of Oklahoma and Southwestern Kansas that will enhance our CO₂ plans in this area. 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.

In connection with the acquisition of Calumet, we acquired properties with significant drilling, rework and enhancement recovery opportunities, as discussed below:

North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is the largest property in the Calumet acquisition. The unit was developed in the early 1920’s and is 22,440 acres in size

Index to Financial Statements

and has a cumulative production of 316 million Bbls of oil (primary and secondary). The North Burbank Unit accounted for 196,657 MMcfe of our proved reserves, $202.7 million of our PV-10 value as of December 31, 2006 and 215 MMcfe of our year ended December 31, 2006 production. The producing zone is Red Fork and Bartlesville and occurs at a depth of 3,000 feet. We own 99.25% of the field and we are also the operator. As of December 31, 2006, the field was producing 1,340 Bbls per day from 214 producing wells. There are 237 producing wells, 160 injection wells and 555 temporarily abandoned wells at this time. Upside potential exist in restoring a majority of the temporarily abandoned wells to production and in expanding the polymer EOR program that Phillips Petroleum Company instituted in the field from 1980-1986 as a pilot on 1,440 acres. Production increased from 500 Bbls per day to 1,200 Bbls per day in this pilot area as a result of the polymer injection program. The pilot was shut down in 1986 due to low oil prices. We have already reinstituted a polymer flood on 480 acres adjacent to Block A on a 19-well pattern. We have already returned 27 temporarily abandoned wells to production with rates of production ranging from 6–25 Bbls per day. We believe that this field also may have upside with the injection of CO₂.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit which is 2,235 acres was discovered in 1915 and unitized in 1977. This unit had proved reserves of 24,130 MMcfe and a PV-10 value of $52.8 million at December 31, 2006. We operate this unit with a working interest of 79.44%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 14 MMBbls of oil and the unit currently has 63 producing wells and 46 injection wells. The unit produced 135 MMcfe for the year ended December 31, 2006. We are in the final stages of the completion phase of a 4 well pilot program to increase density from 10 acre spacing to 5 acre spacing. Production from all four wells has added about 70-80 Bbls of oil per day to the unit production along with about 30 Bbls of oil per day from the Sims reservoir still under a retrievable bridge plug. This Sims reservoir is prospective in much of the field. If the pilot program proves successful, we think this could open up 80 additional drilling locations in the area. None of the Sims reserves were booked as PUD reserves at year end 2006. Additional potential exists in waterflood pattern modification and CO₂ EOR recovery.

Sivells Bend Unit—Cooke County, Texas. The Sivells Bend Unit is 3,863 acres in size, produces primarily from the Strawn formation, which occurs at a depth of 9,000 feet, and has recovered 39 MMBbls of oil to date. This unit represents 12,914 MMcfe of our proved reserves and $30.7 million of our PV-10 value at December 31, 2006. There are currently 27 producing wells and 17 injection wells, with production for the year ended December 31, 2006 of approximately 34 MMcfe. Upside potential exists in increased density drilling from 80 acres to 40 acres in the Strawn. The only 40-acre increased density well drilled in the unit has recovered over 390 MBbls. Additional potential exists in the deeper Ellenburger formation, which is the deepest oil producing horizon in North Texas. An Ellenburger well tested approximately 193 Bbls per day in 1964 in the adjacent East Sivells Bend Unit and one well in our unit tested 104 Bbls per day for a short time. 3D seismic will be required to better define the fault blocks for an Ellenburger test. We own approximately 1,000 acres of fee minerals in this Sivells Bend Unit and own approximately half of the rights below the Strawn, which includes the Ellenburger.

The Permian Basin Area is the second of our two core areas and, as of December 31, 2006, accounted for 10% of our proved reserves and 11% of our PV-10 value. We own an interest in 1,487 wells in the

Index to Financial Statements

Permian Basin, of which we operate 312. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2006, our net average daily production in the Permian Basin Area was approximately 15.1 MMcfe per day, or 17% of our total net average daily production. During the nine months ended September 30, 2007, our net average daily production in this area was approximately 17.6 MMcfe per day, or 16% 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%. The Tunstill field play represents 13,937 MMcfe of our proved reserves, $21.9 million of our PV-10 value at December 31, 2006 and 722 MMcfe of our year ended December 31, 2006 production. 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 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 2006, we drilled ten wells in this play. We have drilled seven wells to date in 2007 and have plans to drill 15 wells in 2008. We have acquired leasehold rights to approximately 13,360 acres that are an expansion to our original Tunstill field play.

Haley Area: Bone Springs, Atoka, Strawn and Morrow Play—Loving County, Texas. The Haley Area: Bone Springs, Atoka, Strawn and Morrow Play encompasses 3,840 gross acres. We own interests in and operate eight producing wells in this play. The Haley Area represents 17,418 MMcfe of our proved reserves, $32.2 million of our PV-10 value at December 31, 2006 and 896 MMcfe of our year ended December 31, 2006 production. Production has been established from four main intervals: the Bone Springs at a depth of approximately 9,500 feet, the Atoka at a depth of approximately 16,000 feet, 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 Atoka, two are completed in the Strawn, three are completed in the Morrow and two are completed in the Bone Springs. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Atoka/Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. During 2006, we drilled two wells in this area. The Haley 36-4 is currently producing approximately 2,400 Mcf per day from the Morrow Sand. The Haley 38-2 is currently producing approximately 425 Mcf per day from the Atoka Lime and has developed Bone Springs behind pipe. We have drilled two offsets (Haley 38-3 and Haley 38-4) to test this Bone Springs. The Haley 38-3 is currently testing at rates of 100-120 Bbls of oil per day. Additional developmental Bone Springs wells will follow. We are currently drilling the Bowdle Estate 47-2 and F.D. Russell #2 to test the Morrow and Atoka intervals. Bowdle Estate 47-2 offsets a Chesapeake well that tested the Morrow at 20 MMcfe per day.

Ark-La-Tex is one of our four growth areas and, as of December 31, 2006, accounted for 3% of our proved reserves and PV-10 value. We own an interest in 128 wells in the Ark-La-Tex area, of which we operate 53. 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. This field accounts for 5,907 MMcfe of our proved reserves, $9.8 million of our PV-10 value at December 31, 2006 and 626 MMcfe of our year ended December 31, 2006 production. We operate this field with an average working interest of 98%. Ten wells are producing from the Edwards Lime that occurs at a depth of 10,100 feet. These ten wells have

Index to Financial Statements

produced 573 MBbls of oil and 44.2 Bcf of natural gas. 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 9 wells. The Winnsboro field accounts for 5,694 MMcfe of our proved reserves, $6.7 million of our PV-10 value at December 31, 2006 and 232 MMcfe of our production for the year ended December 31, 2006. 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.

North Texas is the second of our four growth areas and, as of December 31, 2006, accounted for 2% of our proved reserves and 3% of our PV-10 value. We own an interest in 772 wells in North Texas, of which we operate 115. One of our four 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. The Percy Jones Clearfork Play accounted for 4,182 MMcfe of our proved reserves, $6.9 million of our PV-10 value at December 31, 2006 and 202 MMcfe of our year ended December 31, 2006 production. 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 25 producing wells and is developed on 10 acre spacing with some increased density development to 5 acres and cumulative production of 2.7 MMBbls of oil and 24 MMcf of natural gas. The Percy Jones A and B leases make up the south half of the section, have a total of 12 producing wells and have cumulative production of 495 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 12 producing 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.

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 and Atoka at approximately 5,600 feet to 5,700 feet. As of December 31, 2006, these units accounted for 2,028 MMcfe of our proved reserves and $4.5 million of our PV-10 value. Production for the year ended December 31, 2006 was approximately 198 MMcfe. 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 30 active producing wells in this area. We drilled six wells in 2005 with completion and testing finished in 2006 with all wells completed successfully.

Index to Financial Statements

The Rocky Mountains is our third growth area and, as of December 31, 2006, accounted for 3% of our proved reserves and 4% of our PV-10 value. We own an interest in 155 wells in the Rocky Mountains Area, of which we operate 42. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

Bakken Horizontal Play—Richland County, Montana. In 2005, we drilled a dual leg horizontal well in the Bakken interval on acreage we own that was producing from the Red River formation. As of December 31, 2006, the Bakken Horizontal Play accounted for 4,708 MMcfe of our proved reserves and $11.9 million of our PV-10 value. Production for the year ended December 31, 2006 was approximately 327 MMcfe. 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. As of December 1, 2007, the well was producing 96 Bbls of oil per day and 145 Mcf of natural gas per day.

We recently leased approximately 9,400 acres in the immediate area of the McVay #2-34H and have drilled five additional wells in 2006 with initial rates ranging from 130 Bbls of oil per day to 375 Bbls of oil per day.

Our fourth growth area is the Gulf Coast and, as of December 31, 2006, accounted for 5% of our proved reserves and 6% of our PV-10 value. We own an interest in 191 wells in the Gulf Coast, of which we operate 127. Unlike our core areas, the Gulf Coast Area is characterized by shorter life and high initial potential production. We believe a balance of this type of production compliments our long-life reserves and adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Nueces County, TX. We control approximately 9,018 net producing acres in this area. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate nine active producing wells in this area. As of December 31, 2006, the wells in Nueces County, Texas accounted for 1,718 MMcfe of our proved reserves, $3.5 million of our PV-10 value and 207 MMcfe of our year ended December 31, 2006 production. We recently shot and are currently processing a 3-D seismic survey 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. As of December 31, 2006, the wells in Lavaca County, Texas accounted for 1,382 MMcfe of our proved reserves, $2.9 million of our PV-10 value and 153 MMcfe of our year ended December 31, 2006 production. 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, we expect to propose and budget additional leasing and drilling activity. We have drilled two deep tests in 2007 with the Vivian Borchers 2-14 currently completing in the Zoellar and Dagg after testing at 2,400 Mcf per day in the Rinard. We have plans to drill three shallow and two deep tests in this area in 2008.

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The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2006. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (44% of PV-10 value) and by Lee Keeling & Associates, Inc. (41% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (15% of PV-10 value).

The reserve life as of December 31 2004, 2005 and 2006 was 22.9, 24.4 and 28.0 years, respectively. The reserve life was calculated by dividing total proved reserves by production volumes for the year indicated.

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.

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, 2006 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.

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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, 2006 by area.

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2006.

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.

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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.

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.

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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 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.

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.

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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:

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, 2006, 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 2007 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:

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.

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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.

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.

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.

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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.

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.

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.

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

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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.

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.

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:

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.

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

Index to Financial Statements

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. 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.

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.

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.

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.

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

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the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business.

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.

As of September 30, 2007, we had 722 full-time employees, including 11 geologists and geophysicists, 30 production and reservoir engineers and 11 land professionals. Of these, 252 work in our Oklahoma City office, 303 are in our district and field offices and 167 are associated with Green Country Supply. 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.

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

The following table provides information regarding our executive officers and directors. Our board of directors currently consists of three members—Mark A. Fischer, Charles A. Fischer, Jr. and Joseph O. Evans. Mark A. Fischer and Joseph O. Evans are also full-time employees. We currently have no Board committees.

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.

Joseph O. Evans, Chief Financial Officer & Executive Vice President & Director, joined Chaparral in July of 2005 as Chief Financial Officer and was elected to its Board of Directors in September 2006. 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.

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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 American Bar Association, 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 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.

Charles A. Fischer, Jr., Director and Co-Founder, co-founded Chaparral in 1988, and served as its Chief Administrative Officer and Executive Vice President from July 2005 until his retirement effective July 27, 2007. 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 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).

Index to Financial Statements

Upon completion of our current proposed initial public offering of common stock, if consummated, our board of directors will consist of six members and will include three independent directors to be identified prior to completion of the offering. Our board will determine the independence of these directors under the applicable rules of the NYSE which require that a director have no material relationship with us in order to qualify as “independent.” These rules take into consideration such factors as a director’s (or his immediate family member’s) relationship as an officer of our company, direct compensation received by such persons from our company, such persons’ relationship with our internal or external auditor, compensation committee interlocks between such persons and our executive officers, and payments between us and other companies for which such persons are employees. The phase-in rules of the NYSE allow companies listing in connection with their initial public offering to satisfy the rule that a majority of the members of its board of directors be independent within 12 months of the date of listing with the NYSE. However, a company of which more than 50% of the voting power is held by an individual, a group or another company may rely upon the controlled company exemption and need not comply with the NYSE requirement that it must have a majority of independent directors. 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 2008, 2009 and 2010, 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. All other directors will receive an annual retainer of $25,000 and an annual grant of 4,000 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.

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 as of the date of effectiveness of the registration statement of which this prospectus is a part. The phase-in rules of the NYSE allow companies listing in connection with their initial public offering to phase in the minimum number of members on its audit

Index to Financial Statements

committee pursuant to the following schedule: one member at the time of listing, two members within 90 days of listing and three members within one year.

The phase-in rules of the NYSE also allow companies listing in connection with their initial public offering to phase in its independent nominating and governance committee and compensation committee pursuant to the following schedule: one independent member at the time of listing, a majority of independent members within 90 days of listing and fully independent committees within one year. However, a company relying on the controlled company exemption need not comply with the NYSE requirement that its nominating and governance committee and compensation committee be composed entirely of independent directors. 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. As long as we rely on the controlled company exemption, neither our nominating and governance committee nor our compensation committee will be required to include any members who are independent.

Audit Committee. The audit committee, 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 will designate one of the members of the audit committee as an “audit committee financial expert.”

Nominating and Governance Committee. The nominating and governance committee, 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 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 (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.

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.

Index to Financial Statements

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. During the last completed fiscal year, we did not have a compensation committee. Each of the members of our Board of Directors is also an executive officer of the company and participated in deliberations concerning executive officer compensation.

Index to Financial Statements

Our compensation programs include programs that are designed specifically for (1) our most senior executive officers (“Senior Executives”), which includes the Principal Executive Officer (“PEO”) and the other executive officers named in the Summary Compensation Table (the “Named Executive Officers” or “NEOs”); (2) employees who are designated as executives of Chaparral (“Executives” or “Executive Employees”), which includes the Senior Executives and (3) a broad-base of Chaparral employees.

Our PEO and Board of Directors determine and authorize the compensation programs and awards for the Senior Executives. The Board of Directors also determines and authorizes the compensation levels, programs and awards for the PEO. As a privately-held company in 2006 and 2007, the PEO, as the Chairman and member of the three person Board of Directors had and will have significant participation in the deliberation, determination and authorization of his own compensation package. Upon completion of our initial public offering, our Board of Directors will include a Compensation Committee comprised of independent members in accordance with the phase-in rules of the NYSE that 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 (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.

In order to recruit and retain the most qualified and competent individuals as Senior Executives, we strive to maintain a compensation program that is competitive in the labor market. The following compensation objectives are considered in setting the compensation programs for our Senior Executives:

We selected a group of companies consisting of 27 publicly-traded, U.S. exploration and production companies of varying sizes (the “Benchmark Group”). The Benchmark Group is used to index executive compensation levels against companies that have executive positions with responsibilities similar in breadth and scope to ours and that compete with us for executive talent. For 2006, the Benchmark Group was ATP Oil & Gas Corp., Berry Petroleum Co., Bill Barrett Corp., Brigham Exploration Co., Cabot Oil and Gas Corp., Callon Petroleum Co., Carrizo Oil and Gas, Inc., CNX Gas Corp., Comstock Resources, Inc., Denbury Resources, Inc., Edge Petroleum

Index to Financial Statements

Corp., Encore Acquisition Co., Energy Partners Ltd., Harvest Natural Resources, Houston Exploration, Meridian Resources Corp., Parallel Petroleum Corp., Penn Virginia Corp., Petrohawk Energy Corp., Petroleum Development Corp., Petroquest Energy, Inc., Quest Resources Corp., Quicksilver Resources, Inc., Stone Energy Corp., Swift Energy Co., Western Gas Resources, Inc., and Whiting Petroleum Corp.

We also review compensation data from the Oil & Gas E&P Survey prepared by Effective Compensation, Incorporated (“ECI” or the “Survey Data”) to ensure that our total Senior Executive compensation program aligns with the median of the Survey Data. The Survey Data is a compilation of compensation and other data based upon 99 exploration and production firms that participated in the survey.

To reward both short and long-term performance in our compensation program and in furtherance of our compensation objectives noted above, our executive compensation philosophy includes the following four principles:

We review the Survey Data to ensure that the compensation program is aligned with median levels. We believe that a competitive compensation program will enhance our ability to attract and retain Senior Executives.

We believe that a significant portion of a Senior Executive’s compensation should be tied to individual performance and within the context of our overall performance measured primarily by growth in reserves, production and net income. Senior Executives should have the incentive of increasing our profitability and value in order to earn a portion of their compensation package.

(iii) Variable compensation should represent a portion of a Senior Executive’s total compensation

We intend for a portion of compensation paid to Senior Executives to be variable in order to allow flexibility when our performance and/or industry conditions are not optimum and maintain the ability to reward Senior Executives for our overall growth and retain Senior Executives when industry conditions necessitate.

We seek to structure a balance between achieving strong short-term annual results and ensuring our long-term viability and success. To reinforce the importance of balancing these perspectives, Senior Executives are regularly provided both compensation based on the accomplishment of short-term objectives and incentives for achieving long-term objectives. Beginning in 2004, we began a long-term compensation plan for non-owner Senior Executives and other key employees, to deliver long-term incentive awards aligned with the interests of stockholders while simultaneously serving as a retention tool to ensure that recipients remain employed while our annual bonus plans are structured to reward the accomplishment of short-term objectives.

The PEO and the Board of Directors base their decisions with respect to compensation of our Named Executive Officers for services rendered in 2006 upon these principles and their

Index to Financial Statements

assessment of each officer’s potential to enhance long-term shareholder value, level of responsibility and authority, each executive officer’s current salary and prior year compensation, as well as compensation paid to the executive officer’s peers.

The PEO reviews, on an annual basis, each compensation element of a Senior Executive. In each case, the PEO takes into account the scope of responsibilities and experience, succession potential, strengths and weaknesses, and contribution and performance over the past year and balances these against competitive salary levels. The PEO works daily with the Senior Executives, which allows him to form his assessment of each individual’s performance. The PEOs performance is assessed by the Board, taking into account the scope of responsibilities and experience, strengths and weaknesses and contribution and performance over the past year balanced against competitive salary levels.

We believe the total compensation and benefits program for Senior Executives should consist of the following:

Senior Executive base salaries are targeted at or around the 50^th percentile of base salaries of similarly sized companies within the Benchmark Group and Survey Data. Base salaries are determined by evaluating a Senior Executive’s level of responsibility and experience and our performance.

Increases to base salaries, if any, are driven primarily by individual performance and comparative data from the Survey Data. Individual performance is evaluated by reviewing the Senior Executive’s success in achieving business results, promoting our core values and keys to success and demonstrating leadership abilities.

In setting the base salary of the Senior Executives for fiscal year 2006, the compensation of comparable senior executives based on Survey Data was reviewed. The percent increase in median level compensation based on Benchmark Group data and Survey Data for various levels is computed and used as the baseline for annual increases. The PEO does not, however, rely solely on predetermined formulas or a limited set of criteria when evaluating the performance of the Senior Executives.

We review the Survey Data annually. The Survey Data and general economic conditions and marketplace compensation trends are evaluated. We usually adjust base salaries for Senior Executives annually or when:

Index to Financial Statements

This is in line with our philosophy that Senior Executive compensation should be paid at the competitive median levels. The salaries paid to the PEO and the NEOs during fiscal year 2006 are shown in the Summary Compensation Table below.

The Annual Profit Sharing Bonus provides Senior Executives with the opportunity to earn cash bonuses based on our achievement of unspecified company-wide goals as determined by the PEO. The annual profit sharing bonus component of our compensation program is to align Senior Executive pay with our annual (short-term) performance. The profit sharing bonus was awarded to all employees. All employees, from the most senior executives to entry level have historically received the same percentage level bonuses. For 2006, we awarded and paid an Annual Profit Sharing Bonus of 8% of annual base salary which is consistent with historical percentages and was determined by the PEO and Board of Directors based on our continued reserve, production and revenue growth. In 2006, one-half of the 2005 annual profit sharing bonus was paid in cash in June 2006 and for Senior Executives, the entire 2006 annual profit sharing bonus was paid in cash in December 2006.

The Annual Performance Based Retention Bonus (“Retention Bonus”) provides all employees, including Senior Executives in 2006, with the opportunity to earn cash bonuses. The Retention Bonus is a component of our compensation program designed to enhance retention on short- term basis and to balance the long-term retention plans. In 2006, the amount of Retention Bonus awards were determined based on position and unspecified subjective performance criteria as determined by the PEO for the Senior Executives and by the Board for the PEO, which targeted the Senior Executives, with the exception of the PEO, at 10% of annual base compensation. All Senior Executives received the targeted 10% bonus for 2006. The PEO’s bonus was targeted and paid at $100,000. The Retention Bonus was announced in November 2005 and was paid in cash one-half in March 2006 and one-half in September 2006.

Both the Profit Sharing and Retention Bonus for Senior Executives were discontinued after September 2006 and a new Officers Annual Bonus program was created in September 2006. The bonus under the Officers Annual Bonus program were designed to supplement the other bonus and compensation programs such that the officers received total annual compensation for 2006 inline with the Benchmark Group data and Survey Data for equivalent positions. The Officers Annual Bonus provides Senior Executives with the opportunity to earn cash bonuses based on our achievement of unspecified company-wide goals as determined by the PEO, generally subjectively determined by the Board based on overall reserve, production, and revenue growth. The bonus is a component of the compensation program designed to align Senior Executive pay with our annual (short-term) performance and provide competitive compensation packages. The bonus was awarded in September 2006 and was paid April 2, 2007.

The 2006 bonus programs were structured to provide cash bonuses to Senior Executives competitive to the median levels based on the Benchmark Group and the Survey Data to be consistent with our philosophy that compensation levels should be variable and competitive.

Index to Financial Statements

Under all of the bonus programs, the determinations are made, not based on arithmetic methods or formulas, but generally based on our overall corporate results. Any measure that might be considered to indicate whether an oil and gas company had a “good year” may be considered by the PEO and Board of Directors. These measures have included evaluation of production levels, achievement of major reserve acquisition target, completion of significant transactions or projects, operating and administrative expense levels, and/or changes in our proved, probable and possible reserves for a period compared to costs incurred. The PEO’s and Board of Directors’ decisions are subjective evaluations made on an overall basis and it is not possible to determine how these measures are weighted. Because we do not offer non-equity incentive plans, stock awards, options or pensions, the bonuses paid to the CEO, Chief Financial Officer, and Chief Administrative Officer were paid in excess of median levels so that total compensation paid to these officers was within the median levels for their equivalent positions. None of the other NEO’s were awarded bonuses that placed their total compensation outside of the median levels for their equivalent positions. The bonuses awarded paid to the PEO and the NEOs during fiscal year 2006 are shown in the Summary Compensation Table below.

The Phantom Unit plan is a deferred compensation plan. The objective of the Phantom Unit plan is to provide Senior Executives who are not stockholders and other key employees with long-term incentive and retention award opportunities that would be competitive with equity incentive plans provided by public companies.

The term “phantom unit” refers to units of value that trace our fair market value, as defined by the plan. The units are not convertible into stock and do not possess any voting rights. Phantom units are exchanged for cash upon vesting. Phantom units may be awarded in total up to 2% of our fair market value, 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 us without cause. Effective January 1, 2007, we reduced the phantom unit vest period from the seventh anniversary of the award date to the fifth anniversary of the original award date in an effort to meet market demand and recruit and retain essential personnel.

Also, phantom units vest if a change of control event occurs. A change of control event will occur under the Plan if (1) our stockholders as of January 1, 2004, the date of the creation of the Phantom Unit Plan, 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, is not held by either Mark A. Fischer or Charles A. Fischer, Jr.), (2) the termination, liquidation or dissolution of us or Chaparral Energy 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.

The Phantom Unit plan was effective January 1, 2004. At the creation of the plan, the value of the initial and nine subsequent annual awards made to Senior Executives was targeted. The value and timing of the awards was derived to provide an estimated pre-determined payout upon vesting of the awards. The payout was determined in 2003 by the PEO and Board of Directors

Index to Financial Statements

based on what they believed would provide retention incentive for senior officer positions. The payout on vesting of the awards assumed certain company growth rates were sustained over the vesting period, although no adjustment is made to those awards if Chaparral exceeds or does not meet those growth rates. We believe that this aligns the Senior Executives compensation to stockholder value by providing a proprietary interest in the value of Chaparral. Although no adjustments were made for 2006, the predetermined annual awards can be adjusted to recognize exemplary performance or increased responsibility consistent with the philosophy of relating individual compensation to performance.

Phantom unit information related to the NEOs during fiscal year 2006 is included in the Summary Compensation Table below. Additional information on the phantom unit awards is shown in the Grants of Plan Based Awards Table below and the Outstanding Awards at Fiscal Year-End Table below.

Section 162(m) of the Internal Revenue Code of 1986, as amended (the “Code”) places a limit of $1,000,000 on the amount of compensation that may be deducted by Chaparral in any year with respect to the PEO and the NEOs unless the compensation is performance-based compensation as described in Section 162(m) and the related regulations, as well as pursuant to a plan approved by Chaparral’s stockholders. We may from time to time pay compensation to our Senior Executives that may not be deductible, including discretionary bonuses or other types of compensation outside of our plans, such as recruitment or retention, when it is consistent with our overall philosophy.

Although we have generally attempted to structure executive compensation so as to preserve deductibility, we also believes that there are circumstances where our interests are best served by maintaining flexibility in the way compensation is provided, even if it might result in the non-deductibility of certain compensation under the Code.

Although equity awards may be deductible for tax purposes by Chaparral, the accounting rules pursuant to FAS 123(R) require that the portion of the tax benefit in excess of the financial compensation cost be recorded to paid-in-capital.

We offer a variety of health and welfare and retirement programs to all eligible employees. The Senior Executives are eligible for the same benefit programs on the same basis as the rest of our employees. The health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. Our health and welfare programs include medical, pharmacy, dental, life insurance, supplemental insurance policies and a flexible spending plan. For employees, including Senior Executives, that decline coverage or elect employee only coverage on the medical, Chaparral will provide a $50 per month credit to use to purchase dental, voluntary products or deposit into a flexible spending plan which allows employees to pay for out-of-pocket medical, dental and vision expenses and dependent care expenses.

We offer a 401(k) Profit Sharing Plan that is intended to supplement the employee’s personal savings and social security. All employees, including Senior Executives, are generally eligible for the 401(k) plan. Senior Executives participate in the 401(k) plan on the same basis as other employees.

Index to Financial Statements

We adopted the 401(k) plan to enable employees to save for retirement through a tax-advantaged combination of employee and company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. The 401(k) plan allows eligible employees to elect to contribute from 1% to 60% of their eligible compensation, up to the annual IRS dollar limit. Eligible compensation generally means all wages, salaries and fees for services from Chaparral. Employee contributions are matched in cash by us at the rate of $1.00 per $1.00 employee contribution for the first 5%. Effective January 1, 2007, Chaparral matches to a rate of $1.00 per $1.00 employee contribution for the first 6% of the employee’s salary. Effective January 1, 2007, such contributions vest as follows:

However, regardless of the number of years of service, an employee is fully vested in his 401(k) plan if the employee retires at age 65 or later, attains age 62 and completes 5 years of service, or the employee’s employment is terminated due to death or total and permanent disability. The 401(k) plan provides for different investment options, for which the participant has sole discretion in determining how both the employer and employee contributions are invested. The 401(k) plan does not provide our employees the option to invest directly in Chaparral’s stock. The 401(k) plan offers in-service withdrawals in the form of loans, hardship distributions, after-tax account distributions and age 59.5 distributions.

Historically, we had granted participation interests in certain drilling or development projects to a limited number of employees with the objective of directly aligning Chaparral and individual objectives. We granted certain participation interests in the form of overriding royalty interests to James M. Miller as incentive compensation for the development of our largest EOR project. These participation interests were granted to Mr. Miller during a period for which no other incentive compensation programs were in place. The participation interests were granted subject to a vesting schedule to provide retention incentive through the initial phases of the long-term project. Our subsidiary, Chaparral CO₂, L.L.C., has assigned Mr. Miller an overriding royalty interest equal to a total 0.005 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. Mr. Miller was 60% vested at June 30, 2005, 80% vested at June 30, 2006 and 100% vested at June 30, 2007. 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 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. The participation interests information related to Mr. Miller during fiscal year 2006 is included in the Summary Compensation Table below.

We discontinued the program of granting overriding royalty interests to Senior Executives and other employees effective December 31, 2005. Certain employees were awarded Participation

Index to Financial Statements

Interests prior to December 31, 2005 on certain wells that spud between January 1, 2006 and April 1, 2006, therefore making the assignment effective in 2006.

Participation interests that have been granted in prior years that are not subject to vesting were considered compensation in the year in which they were granted. As the interests are not subject to forfeiture, payments received under those participation interests are not considered compensation in the year received and are therefore not included in the 2006 Summary Compensation Table.

We have an employment agreement with our chief financial officer, dated as of June 17, 2005. We 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 an initial public offering on the adoption of a revised severance package.

We have also entered into indemnification agreements with Mark A. Fischer, Charles A. Fischer, Jr., Joseph O. Evans and Robert W. Kelly II. 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 will 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 will 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 will 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:

Index to Financial Statements

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to our directors, officers and controlling persons pursuant to the provisions described above, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by us of expenses incurred or paid by a director, officer or controlling person of ours in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

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.

Index to Financial Statements

The following table below summarizes the total compensation paid or earned by each of the NEO’s for the fiscal year ended December 31, 2006.

Index to Financial Statements

The following table discloses the actual numbers of phantom units granted and the grant date fair value of these awards for each NEO that participates in the Phantom Unit Plan.

The following table shows outstanding phantom unit awards as of December 31, 2006 for each NEO that participates in the Phantom Unit Plan.

The following is a discussion of the amount of compensation payable upon voluntary termination, involuntary termination without cause, termination following a change of control and termination due to death, disability, or retirement. The actual amounts which would be paid to each executive upon termination of employment can only be determined at the time of each such executive’s separation from Chaparral.

Index to Financial Statements

We have an employment agreement with Mr. Evans, dated as of June 17, 2005. We agreed to pay 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 an initial public offering on the adoption of a revised severance package.

If a change in control as defined in the Phantom Unit Plan were to occur prior to the NEO’s termination of employment with us, all of the NEO’s then outstanding phantom unit awards granted by us would become fully vested and nonforfeitable at the earlier of (i) 180 days after the change of control event or (ii) the date beyond which either Mark A. Fischer or Charles A. Fischer, Jr. are not providing full-time management services to Chaparral or a successor company. For each NEO, the number of shares with respect to which the forfeiture restrictions would have lapsed and the value of this accelerated vesting is specified above in the 2006 Outstanding Equity Awards Table.

If any NEO’s participating in the Phantom Unit Plan are terminated by us without cause as a result of a Change in Control, all unvested units will vest as of the date of termination.

Pro rata vesting upon death, disability, retirement or termination of employment by us without cause

Phantom units vest on a pro-rata basis on the January 1 or July 1 which immediately follows the Participants termination of employment with the company due to death, disability, retirement or termination of employment without cause. Pro-rata calculation will be accomplished by dividing the number of years elapsed for the award date to the date of vesting (to a maximum of 5 years) by seven and then multiplying the number of Phantom Units in the award by the result. Phantom units which do not vest hereunder will be forfeited to the company and the participant shall have no further rights with regard to the units. A participant is considered disabled if, in the sole

Index to Financial Statements

determination of the Committee, such participant is subject to a physical or mental condition which renders or is excepted to render the participant unable to perform his or her usual duties for Chaparral. A Participant is considered retired if the participants’ full-time employment with Chaparral terminates at or after the date the Participant attains the age of 65 years. For each NEO, the number of shares with respect to which the forfeiture restrictions would have lapsed and the value of this accelerated vesting is specified above in the 2006 Outstanding Equity Awards Table.

We granted certain participation interests in the form of overriding royalty interests to James M. Miller as incentive compensation. Mr. Miller was 60% vested at June 30, 2005, 80% vested at June 30, 2006 and 100% vested at June 30, 2007. 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. 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.

Regardless of the manner in which an NEO’s employment is terminated, he is entitled to receive amounts earned during his term of employment, including unused vacation pay and bonuses earned but not yet paid under the Officers Annual Bonus. The amounts unpaid Officers Annual Bonuses at December 31, 2006 were $105,233, $45,817, $39,388, $32,851 and $31,996 for Messrs. Mark A. Fischer, Joseph O. Evans, Charles A. Fischer, Jr., Larry E. Gately, and James M. Miller, respectively.

Additionally, if an officer is terminated due to death or disability, an NEO will receive benefits under our disability plan or payments under our life insurance plan.

Index to Financial Statements

The following table sets forth information, as of September 30, 2007, 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 and each of the five most highly compensated executive officers, and by all directors 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.

Index to Financial Statements

Prior to September 30, 2005, Chaparral managed and administered the business of CEI Bristol Acquisition, L.P. 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 $1,018,000 for the year ended December 31, 2004 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 $228,000 for the year ended December 31, 2004 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.

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 $522,965, $612,075 and $622,617 in 2004, 2005 and 2006, respectively. Payments on these interests to Mark A. Fischer were $130,509, $120,373 and $84,837 in 2004, 2005 and 2006, respectively. Payments on these interests to Charles A. Fischer, Jr. were $34,421, $31,758 and $21,919 in 2004, 2005 and 2006, respectively.

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.

In September 2006, Chesapeake Energy Corporation “Chesapeake” acquired a 31.9% beneficial interest in us through our sale of common stock. Chaparral participates in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings of $9,792,000 and $4,361,000, respectively for the year ended December 31, 2006 on these properties. In addition, Chesapeake participates in ownership of properties operated by Chaparral. During the year ended December 31, 2006, we paid revenues and recorded joint interest billings of $1,809,000 and $2,556,000, respectively to Chesapeake. There were no significant amounts receivable or payable to Chesapeake at December 31, 2006.

On December 28, 2005, Mark A. Fischer, our Chairman, Chief Executive Officer and President, 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

Index to Financial Statements

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. The sale of the Port Aransas Property to Mr. Fischer was approved by our board of directors prior to us becoming a public company as it was anticipated that the house would no longer be used for company purposes, and that the house would be solely for Mr. Fischer’s personal use.

On December 7, 2007, our board of directors approved the sale of Pointe Vista Development, L.L.C., an indirect, wholly owned subsidiary of the Company, to Fischer Investments, L.L.C., an Oklahoma limited liability company controlled by Mark A. Fischer, our Chairman, Chief Executive Officer and President, for approximately $3.2 million. The sale of this non-core asset was approved by our board of directors in an effort to focus on our core business areas of oil and gas production and exploitation.

In connection with the closing of the private sale of our common stock to Chesapeake Energy Corporation, we, Chesapeake, Altoma Energy, an Oklahoma general partnership, and Fischer Investments, L.L.C., an entity controlled indirectly by Mark A. Fischer, our Chairman, Chief Executive Officer and President (“Fischer” and together with Altoma, the “Selling Stockholders”) entered into a Stockholders’ Agreement on the closing date of the above transaction.

Board of Directors; Voting. Pursuant to the Stockholders’ Agreement, the parties to the Stockholders’ Agreement have rights to nominate and elect directors prior to the closing of a Qualified Initial Public Offering by Chaparral. A “Qualified Initial Public Offering” is defined as (i) a consummated initial public offering of shares of Common Stock of Chaparral, which is underwritten on a firm commitment basis by a nationally-recognized investment banking firm, or (ii) any transaction resulting in the initial listing or quotation of the shares of Common Stock on a national securities exchange or on the Nasdaq National Market. As long as the Selling Stockholders and their permitted transferees continue to own in the aggregate in excess of 50% of Chaparral’s outstanding shares of Common Stock, Fischer will have the power to nominate and elect two directors to Chaparral’s board of directors (or if there are more than three directors, such number of directors equal to the total number of directors not designated by Fischer), and Altoma (for as long as Altoma and its permitted transferees continue to own in excess of 5% of Chaparral’s outstanding shares of Common Stock) will have the power to nominate and elect one director to Chaparral’s board of directors. At the written election of Chesapeake, Chesapeake (for as long as Chesapeake and its permitted transferees continue to own in excess of 5% of Chaparral’s outstanding shares of Common Stock) has the power to nominate and elect one director to Chaparral’s board of directors. In addition, prior to a Qualified Initial Public Offering, Altoma agrees not to vote for the approval of (i) any merger, consolidation or conversion, (ii) certain amendments to Chaparral’s certificate of incorporation, (iii) the sale of all or substantially all of Chaparral’s assets, or (iv) a termination of Chaparral’s business, unless Fischer votes for such approval.

Index to Financial Statements

Preemptive Rights; Standstill. Subject to the procedures set forth in the Stockholders’ Agreement, if Chaparral proposes to sell any of its capital stock, other than in the context of a Qualified Initial Public Offering, merger or other acquisition, or the issuance of equity securities to employees or directors or in connection with a debt financing, each party to the Stockholders’ Agreement has the right to purchase, upon substantially similar terms and conditions, up to a number of shares sufficient for it to maintain the same percentage ownership of outstanding securities of such class of Chaparral as it owned immediately prior to such issuance. Furthermore, subject to certain exceptions including the preemptive rights described above, Chesapeake agrees that it will not, without the approval of the board of directors of Chaparral, acquire or publicly announce any intention to acquire shares of Common Stock of Chaparral to the extent Chesapeake would hold of record, beneficially own, or otherwise control the voting with respect to, in excess of 35% of the then-outstanding shares of Common Stock of Chaparral.

Transfer of Securities; Tag-Along Rights; Drag-Along Rights. Except as set forth in the Stockholders’ Agreement, the Selling Stockholders and Chesapeake may not transfer any shares of capital stock of Chaparral until (i) such time that Fischer and its affiliates own less than 25% of the shares of Common Stock owned at the time the Stockholders’ Agreement was executed or (ii) the occurrence of a Qualified Initial Public Offering or the expiration of any lock-up period in connection with such Qualified Initial Public Offering, as applicable. Subject to certain exceptions and the procedures set forth in the Stockholders’ Agreement, if Fischer or its permitted transferees proposes to sell more than 25% of the outstanding shares of Common Stock of Chaparral in a bona fide offer to a third party, then such seller must offer to Altoma and Chesapeake the opportunity to include a pro rata number of shares in the proposed sale. Additionally, if Fischer or its permitted transferees or affiliates proposes to sell all of its shares of Common Stock in a bona fide offer, and such shares represent more than 50% of the outstanding shares of Common Stock of Chaparral, then such seller has the right, subject to the provisions of the Stockholders’ Agreement, to require all other parties to the Stockholders’ Agreement to include in such sale all, but not less than all, of such other parties’ shares of Common Stock.

Listing of Shares; Right of First Offer. Under the Stockholders’ Agreement, Chaparral agrees to use its commercially reasonable efforts to effect a Qualified Initial Public Offering prior to August 15, 2011. Altoma agrees (i) not to transfer, without the consent of Fischer, any shares of Common Stock prior to such date except in connection with a Qualified Initial Public Offering, and (ii) in the event of a Qualified Initial Public Offering, to include in such offering a number of shares designated by Chaparral up to the number of shares being sold by Chaparral in such offering, but not to exceed $100 million without the consent of Altoma. If Chaparral’s shares of Common Stock are not listed on an exchange after August 15, 2011, Altoma may request to transfer up to 60% of its shares pursuant to a demand request as described below, but only after Altoma first offers such shares to Chaparral, and then to Chesapeake and Fischer, in accordance with the procedures set forth in the Stockholders’ Agreement.

Subject to certain exceptions, in the event Fischer or Chesapeake desire to transfer shares of Common Stock other than to a permitted transferee or pursuant to a demand request prior to a Qualified Initial Public Offering, such seller will be required to notify the other parties to the Stockholders’ Agreement. Such seller will then negotiate in good faith with such other parties for a period of not less than 21 days, during which time such other party or parties to the Stockholders’ Agreement may deliver notice to such seller of their offer to purchase such shares from the seller. If such seller accepts the offer, each of the parties who timely delivered notice within the 21 days will have a right to acquire their pro rata number of shares.

Index to Financial Statements

Registration Rights; Piggyback Registration. At any time after a Qualified Initial Public Offering, Fischer, Altoma and Chesapeake will have demand rights to require Chaparral to register shares of its Common Stock. Fischer may on up to four occasions, and Altoma and Chesapeake may on up to two occasions each, require Chaparral to register shares of Common Stock after the completion of a Qualified Initial Public Offering, provided that the proposed offering proceeds for the offering equal or exceed $20 million (or $10 million if Chaparral is able to register on Form S-3). In addition, subject to certain exceptions, either Altoma or Chesapeake may make one additional request for a demand registration at any time after May 15, 2011 in the event a registration statement for a Qualified Initial Public Offering has not been filed prior to such date, provided that the proposed offering proceeds for the offering equal or exceed $20 million.

In addition, the parties to the Stockholders’ Agreement may generally require Chaparral to include shares of common stock in a registration statement filed by it other than on Forms S-4 or S-8 or any successor forms. The rights granted under the Stockholders’ Agreement will terminate whenever the shares covered by the Stockholders’ Agreement may be sold under Rule 144(k) or when these shares have been disposed of in connection with a registration statement or under Rule 144.

Our Board of Directors is responsible for approving all related party transactions between Chaparral and any officer or director that would potentially require disclosure. The Board expects that any transactions in which related persons have a direct or indirect interest will be presented to the Board for review and approval and has adopted a written policy regarding related party transactions. Pursuant to the policy, certain key employees may be allowed to invest in certain wells or projects in which we have an ownership position, provided that Board approval is required if the aggregate investment by employees in a single well or project exceeds 5% of our investment, and no individual shall participate with more than a 2% investment in such project. In determining whether to approve such investment, the Board will consider, among other factors, whether there is an appropriate business reason to allow such investment, that the investment is consistent with our Code of Business Conduct, and that the investment shall allocate risks no less favorable to us than to such employee. Chaparral is not aware of any transaction that was required to be reported in its filings with the SEC where such policies and procedures either did not require review or were not followed.

Index to Financial Statements

On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement provided for a $750.0 million maximum commitment amount, is secured by our oil and gas properties and matures on October 31, 2010. Obligations under the Credit Agreement are also secured by pledges by us and each of the borrowers of equity interests in other subsidiaries owned by us and them, excluding specified entities. Availability under our Credit Agreement is subject to a borrowing base, which initially was $750.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. As a result of the issuance of our 8⁷/8% Senior Notes on January 18, 2007, borrowing base was adjusted to $500 million. Effective November 1, 2007 the borrowing base was increased to $525.0 million. As of September 30, 2007, we had $430.0 million outstanding under our Credit Agreement.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2007, all of our borrowings were Eurodollar loans.

Index to Financial Statements

Our Credit Agreement contains restrictive covenants that may limit our ability, among other things, to:

The Credit Agreement requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Credit Agreement, of not greater than:

Index to Financial Statements

Agreement. The amended Credit Agreement requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2007.

Index to Financial Statements

derivatives. At December 31, 2006 and September 30, 2007, our current ratio as computed using generally accepted accounting principles was 0.88 and 0.99, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.15 and 1.76, 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:

On December 1, 2005, we issued $325.0 million aggregate principal amount of 8¹/2% Senior Notes maturing on December 1, 2015. The 8¹/2% 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 8¹/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries, as defined in the indenture.

Index to Financial Statements

On January 18, 2007, 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 reasonable best 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:

Index to Financial Statements

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.”

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 8⁷/8% Senior Notes due 2017 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 integral multiples of $1,000 thereafter.

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 expiration time of the exchange offer is 5:00 P.M., New York City time, on , 2008. 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 conditions in our discretion. Furthermore, we reserve the right to amend or terminate the

Index to Financial Statements

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.

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”:

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 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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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

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.

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:

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

Index to Financial Statements

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:

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.

Index to Financial Statements

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:

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.

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.

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

Index to Financial Statements

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:

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.

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:

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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:

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.

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:

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

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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.

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.

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

Index to Financial Statements

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.

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.

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 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.

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.

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.

Index to Financial Statements

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:

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.

Index to Financial Statements

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 additional interest 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 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.

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

Index to Financial Statements

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 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.

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.

On and after February 1, 2012, 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 on of the years indicated below:

Prior to February 1, 2010 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 108.875% 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

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

Index to Financial Statements

In addition, the Notes may be redeemed, in whole or in part, at any time prior to February 1, 2012 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:

(a) the present value at such redemption date of (i) the redemption price of such Note at February 1, 2012 (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 February 1, 2012, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

“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 February 1, 2012; provided, however, that if the period from the redemption date to February 1, 2012 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 February 1, 2012 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.

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.

Index to Financial Statements

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.

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.

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 September 30, 2007, outstanding Indebtedness of Subsidiary Guarantors was $1.1 billion, of which $447.9 million was secured.

Index to Financial Statements

Although the Indenture will limit 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.”

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 of $1,000 thereafter) 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

Index to Financial Statements

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 of $1,000 thereafter; and

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

(1) accept for payment all Notes or portions of Notes (of at least $2,000 or an integral multiple of $1,000 thereafter) 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 of $1,000 thereafter.

Index to Financial Statements

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 and/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.

Index to Financial Statements

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 will 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.

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.

Index to Financial Statements

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) $500.0 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);

(6) the Incurrence by the Company or any Restricted Subsidiary of Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations, in

Index to Financial Statements

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;

(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;

Index to Financial Statements

(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.

The Indenture will 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.

Index to Financial Statements

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

(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

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to December 1, 2005 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);

Index to Financial Statements

(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 December 1, 2005 (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 December 1, 2005 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.

(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

Index to Financial Statements

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 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

Index to Financial Statements

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 December 1, 2005 (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 December 1, 2005, 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 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;

Index to Financial Statements

(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;

(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 $25.0 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, Pointe Vista and Chaparral Biofuels, L.L.C. 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.

As of September 30, 2007, the Company had approximately $114.1 million of capacity under clause (c) of the first paragraph of this covenant with which to make Restricted Payments.

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 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

Index to Financial Statements

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.

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.

(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;

(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;

Index to Financial Statements

(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;

(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;

Index to Financial Statements

(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.

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 Additional Assets, or any combination thereof; and

Index to Financial Statements

(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

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 denominations of at least $2,000 or an integral multiple of $1,000 thereafter. 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 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.

Index to Financial Statements

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 denominations of at least $2,000 or an integral multiple of $1,000 thereafter. 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 $1,000 thereafter. 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.

Index to Financial Statements

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.

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

Index to Financial Statements

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 $25.0 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.

(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

Index to Financial Statements

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.

The Indenture will provide 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.

Index to Financial Statements

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.

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

Index to Financial Statements

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.”

The Indenture will provide 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.

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.

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 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.

Index to Financial Statements

(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 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

Index to Financial Statements

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;

(3) such holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

Index to Financial Statements

(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.

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;

(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 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;

Index to Financial Statements

(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:

(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;

(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;

(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

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

Index to Financial Statements

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.

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.

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

Index to Financial Statements

(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 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.

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.

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.

“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 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.

(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

Index to Financial Statements

(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:

(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

(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),

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

Index to Financial Statements

(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;

(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 “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

Index to Financial Statements

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;

(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”;

(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;

(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;

(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;

Index to Financial Statements

(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.

“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.

Index to Financial Statements

(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.

(1) 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 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);

(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;

Index to Financial Statements

(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).

“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:

(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 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;

Index to Financial Statements

(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 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

Index to Financial Statements

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:

(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).

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.

Index to Financial Statements

“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);

(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

(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.”

Index to Financial Statements

“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;

(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;

(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

Index to Financial Statements

(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.

“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

Index to Financial Statements

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.

“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,

Index to Financial Statements

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 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);

Index to Financial Statements

(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 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);

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.

(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

Index to Financial Statements

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

(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

Index to Financial Statements

(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.

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.

Index to Financial Statements

“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;

(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).

Index to Financial Statements

“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.

(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.

“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.

Index to Financial Statements

“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

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

(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

Index to Financial Statements

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;

(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”;

(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”;

(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);

(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;

Index to Financial Statements

(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;

(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).

(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”;

(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;

Index to Financial Statements

(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 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

Index to Financial Statements

(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;

(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;

(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;

Index to Financial Statements

(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 $15.0 million;

(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, 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”;

Index to Financial Statements

(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.

“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.

“Pointe Vista” means Pointe Vista Development, L.L.C., an Oklahoma limited liability company, together with any successor entity, so long as such entity is engaged primarily in real estate development and management.

“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

Index to Financial Statements

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

(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.

Index to Financial Statements

“Senior Secured Credit Agreement” means the Seventh Restated Credit Agreement dated as of October 31, 2006 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, 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 (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 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., CEI Pipeline, L.L.C., Calumet Oil Company and JMG Oil & Gas, LP, and any Restricted Subsidiary created or acquired by the Company after the Issue Date (other than a Foreign Subsidiary) that Incurs any Indebtedness.

Index to Financial Statements

(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

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:

(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 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.

Index to Financial Statements

“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.

Index to Financial Statements

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.

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 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, between participants through electronic book-entry changes to the accounts of its participants,

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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:

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.

Index to Financial Statements

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.

Index to Financial Statements

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 , 2008, 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.

Index to Financial Statements

The validity of the new notes and certain other matters will be passed upon for us by Andrews Kurth LLP, Houston, Texas.

The consolidated financial statements of Chaparral Energy Inc. and subsidiaries as of December 31, 2005 and 2006 and for each of the three years in the period ended December 31, 2006, the combined financial statements of Calumet Oil Company and Subsidiary and JMG Oil & Gas, LP as of December 31, 2005 and September 30, 2006 and for the years ended December 31, 2004 and 2005 and the nine months ended September 31, 2006 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 accountants, as stated in their reports appearing herein, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

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, 2005 and 2006 and the net proved oil and natural gas reserves of Calumet Oil Company and Subsidiary and JMG Oil and Gas LP as of September 30, 2006 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.

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.

Index to Financial Statements

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 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.

Index to Financial Statements

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and subsidiaries as of December 31, 2005 and 2006, and the related consolidated statements of income, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2006. 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, 2005 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

Index to Financial Statements

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

Index to Financial Statements

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

Index to Financial Statements

Consolidated statements of stockholders' equity and comprehensive income (loss)

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

Index to Financial Statements

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

Index to Financial Statements

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 years ended December 31, 2005 and 2006, the Company entered into capital lease obligations of $70 and $140, respectively, for the purchase of machinery and equipment. During the nine months ended September 30, 2007, the Company entered into a capital lease obligation of $21 for the purchase of machinery and equipment and recorded non-cash additions to oil and gas properties of $1,113.

During the years ended December 31, 2004, 2005 and 2006, the Company recorded non-cash additions to oil and gas properties of $2,979, $9,367 and $7,317, respectively.

During the years ended December 31, 2004, 2005, and 2006, the Company recorded an asset and related liability of $2,115, $4,680 and $10,813, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties. During the nine months ended September 30, 2006 and 2007, the Company recorded an asset and related liability of $1,340 and $209, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $107 and $3 was capitalized during the years ended December 31, 2004 and 2005, respectively, primarily related to the construction of the Company’s office building and other construction projects. Interest of $1,001, $669 and $1,180 was capitalized during the year ended December 31, 2006 and the nine months ended September 30, 2006 and 2007, respectively, primarily related to the acquisition of unproved oil and gas leaseholds. During the nine months ended September 30, 2007 interest of $32 was capitalized related to the construction of the Company’s office building.

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

Index to Financial Statements

Chaparral Energy, Inc. and subsidiaries, (collectively, “we”, “our”, “us” or 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, Montana and Wyoming. Beginning in April 2007, the Company expanded its operations to include oil and gas services through the acquisition of Green Country Supply, Inc. (“GCS”). GCS provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned and majority owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

The loss from operations related to the minority interest of Oklahoma Ethanol, LLC is shown separately in the statement of income. As the minority interests’ share of the losses has exceeded their equity and there is no obligation for the minority interest holders to fund those losses, the minority interest balance is reported as zero in the consolidated balance sheet and all losses are therefore recognized by the Company. If future earnings materialize, the Company will recognize all earnings up to the amount of those losses previously absorbed.

The financial information as of September 30, 2007 and for the three months and nine months ended September 30, 2006 and 2007 is unaudited. In the opinion of management, such information contains all adjustments consisting 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, 2007 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2007.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for

Index to Financial Statements

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.

The Company considers all highly liquid investments with an original maturity of three months or less to be 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.

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, 2005 and 2006 were $694 and $1,034, 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, 2004, 2005, and 2006 was $248, $140, and $553, 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:

Inventories are comprised of equipment used in developing oil and gas properties, oil and gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the specific identification method and average

Index to Financial Statements

cost method, respectively. Oil and gas product inventories are stated at the lower of production cost or market. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory. Inventories at December 31, 2006 and September 30, 2007 consist of the following:

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:

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

Index to Financial Statements

Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging equipment. Depreciation, depletion and amortization expense of oil and gas properties was $14,596, $27,650, and $47,086 for the years ended December 31, 2004, 2005, and 2006, respectively. Depreciation, depletion and amortization expense of oil and gas properties was $10,699 and $20,468 for the three months ended September 30, 2006 and 2007, respectively, and $31,700 and $58,128 for the nine months ended September 30, 2006 and 2007, respectively.

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.

During 2006, the Company purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. The Company’s expected return on the investment will be receipt of $2 of tax credits for every $1 invested to be recouped from our Oklahoma production taxes. The investments will be accounted for as a production tax benefit asset and will be netted against tax credits realized in other income using the effective yield method over the expected recovery period. The production tax benefit assets are included in other assets in the consolidated balance sheets.

The Company has funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following:

Upon clearing of the title defects, the amount in escrow will be disbursed. If the title defects are not cleared in a manner satisfactory to the Company, the amount will be returned to the Company.

The Company is entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank field which was included in the Calumet acquisition, provided that written documentation has been provided. The balance is not intended

Index to Financial Statements

to reflect the Company’s total future financial obligation for the plugging and abandonment of these wells.

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 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.

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48 (“Fin 48”), Accounting for Uncertainty in Income Taxes-an Interpretation of FASB statement No. 109. FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Under FIN 48, tax positions are recognized in our consolidated financial statements as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with tax authorities assuming full knowledge of the position and all relevant facts. These amounts are subsequently reevaluated and changes are recognized as adjustments to current period tax expense. FIN 48 also revised disclosure requirements to include an annual tabular rollforward of unrecognized tax benefits.

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized no material adjustment in our tax liability for unrecognized income tax benefits. At the adoption date of January 1, 2007, we had approximately $100 of unrecognized tax benefits, all of which would affect our effective tax rate if recognized. At September 30, 2007, the unrecognized tax benefit amount was unchanged from adoption.

If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of September 30, 2007, we have not accrued interest related to uncertain tax positions due to overpayments.

The tax years 1998-2006 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

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

Index to Financial Statements

reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed.

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 rateable 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 rateable 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 aggregate imbalance due to over production is approximately 1,027,000 thousand cubic feet (mcf), 1,866,000 mcf, and 1,903,000 mcf at December 31, 2004, 2005, and 2006, respectively. The Company’s aggregate imbalance due to under production is approximately 1,508,000 mcf, 3,313,000 mcf, and 3,331,000 mcf at December 31, 2004, 2005, and 2006, respectively.

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 2004, 2005, or 2006. The ineffective portions of derivative gains or losses are reported in loss from oil and gas hedging activities on the consolidated statements of income.

Index to Financial Statements

The Company accounts for asset retirement obligations in accordance with 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.

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, 2005 and 2006, 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. As of December 31, 2006, the Company has accrued a liability for site restoration costs of $1,600 related to properties acquired in 2006. The liability is included in accounts payable and accrued liabilities in the consolidated balance sheets.

Basic earnings per share is computed by dividing net income attributable to all classes of common shareholders by the weighted average number of shares of all classes of common stock outstanding during the applicable period. Diluted earnings per share is determined in the same manner as basic earnings per share except that the number of shares is increased to assume exercise of potentially dilutive securities outstanding during the periods presented. There were no potentially dilutive securities outstanding during the periods presented.

Index to Financial Statements

In February 2007, the FASB issued SFAS No. 159, ‘The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company will adopt SFAS No. 159 as of January 1, 2008 and is currently evaluating the impact, if any, SFAS No. 159 will have on its consolidated financial statements.

Calumet—On October 31, 2006 the Company acquired all the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for an aggregate cash purchase price of approximately $500,000. The purchase price was paid in cash and financed through an increase in the Company’s existing senior revolving credit facility up to $750,000. As a result of the acquisition, Calumet Oil Company and JMG Oil and Gas, LP became wholly-owned subsidiaries and the results of operations have been included in the consolidated statement of income since October 31, 2006. Calumet owns properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations. In addition to increasing our current average net daily production, many of the properties have significant drilling and enhanced oil recovery opportunities.

Pursuant to the purchase agreement with Calumet, the Company has estimated and recorded a receivable $14,406 due from the previous owners related to working capital at the time of acquisition. The value of the receivable is estimated in accordance with the purchase contract as of December 31, 2006. The estimated receivable may differ from the final settlement amount and may result in an adjustment to the purchase price.

At the closing date of the sale, the Company withheld and deposited into escrow $31,900 of the purchase price payment for oil and gas properties to which title defects were determined during the due diligence process. Pursuant to the agreement, upon clearing of the title defects by the previous owners of Calumet the amount in escrow will be disbursed. If the title defects for a specific property are not cleared in a manner satisfactory to the Company, the amount escrowed for that property will be returned to the Company. As of December 31, 2006, the escrow balance was $21,795 for defects yet to be cleared.

As part of the purchase, the previous owners of Calumet have agreed to make a Section 338 election pursuant to the Internal Revenue Code, and the Company has agreed to reimburse the owners for the amount of depreciation recapture recorded. As of December 31, 2006, the Company has recorded an estimated liability of $7,135 related to the election. The estimated payable may differ from the final settlement amount and may result in an adjustment to the

Index to Financial Statements

purchase price. The liability balance is recorded in accounts payable and accrued liabilities on the table below and on the accompanying consolidated balance sheets.

CEI-Bristol—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.

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. 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 derivative liabilities of $42,108 that were not designated as hedges and were settled on October 3, 2005.

The acquisitions were accounted for using the purchase method in accordance with the provisions of SFAS No. 141, Business Combinations. The calculation of the purchase price and the allocation to assets and liabilities are shown below.

Index to Financial Statements

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, and the operations of Chaparral and Calumet for the years ending December 31, 2005 and 2006 as if the acquisition occurred on January 1, 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.

Green Country Supply. On April 16, 2007, the Company acquired all of the outstanding shares of common stock of Green Country Supply, Inc. (“GCS”) for an aggregate cash purchase price of $25,000, subject to certain post-closing adjustments. The purchase price was paid in cash and financed through the Company’s existing line of credit. GCS was owned by the former shareholders of Calumet Oil Company and provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming. As a result of the acquisition, GCS became a wholly-owned subsidiary and the results of operations have been included in the consolidated statement of income since April 16, 2007. We believe the acquisition of GCS will allow the Company to better control its costs and generate additional revenue through sales to third parties.

At the closing date of the sale, the Company withheld and deposited into escrow $5,029 of the purchase price for certain working capital, environmental and employment adjustments. Pursuant to the agreement, upon settlement of the various requirements, the amount in escrow will be disbursed. If the requirements are not met, the amount escrowed will be returned to the Company. As of September 30, 2007, the entire amount remained in escrow.

Index to Financial Statements

The unaudited pro forma information of the Company set forth below includes the operations of GCS for the three and nine months ended September 30, 2007 as if the acquisition occurred on January 1, 2007. 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.

Major classes of property and equipment consist of the following at December 31:

Index to Financial Statements

Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:

The Company’s results of operations, financial condition 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. To mitigate a portion of this exposure, the Company enters into swap agreements. For swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price 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.

The Company also uses derivative financial instruments to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses.

In connection with the Calumet acquisition, the Company entered into additional commodity swaps and swaption contracts to provide protection against a decline in the price of oil. The swaptions gave the Company the option, but not the obligation, to enter into fixed price oil swaps under which we would receive a fixed commodity price and pay a floating market price, resulting in a net amount due to or from the counterparty. The cost of the swaption contracts was $2,790. We do not believe that these instruments qualify as hedges pursuant to SFAS No. 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses.

Index to Financial Statements

As part of the Calumet acquisition, the Company assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. In accordance with SFAS 141, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $838. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and natural gas revenues upon settlement. For example, if the fair value of the derivative positions assumed does not change, then upon the sale of the underlying production and corresponding settlement of the derivative positions, cash would be paid to the counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.

Pursuant to SFAS 133, the change in fair value of the acquired cash flow hedges from the date of acquisition is recorded as a component of accumulated other comprehensive income (loss). In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs.

All derivative financial instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward market price at the determination date considering the time value of money.

The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

Index to Financial Statements

Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (loss), which is later transferred to earnings when the hedged transaction occurs. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. The ineffective portion of the hedge derivatives and the settlement of effective cash flow hedges is included in gain (loss) on oil and gas hedging activities in the consolidated statements of income and is comprised of the following:

Based upon market prices at September 30, 2007, the Company expects to charge $10,488 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 September 30, 2007 are expected to be settled by December 2011.

The changes in fair value and settlement of derivative contracts that do not qualify as hedges in accordance with SFAS 133 are recognized as non-hedge derivative losses. Non-hedge derivative losses in the consolidated statements of income is comprised of the following:

Hedge settlement payments of $8,088, $3,444 and $5,345 were included in accounts payable and accrued liabilities at December 31, 2005 and 2006, and September 30, 2007, respectively. Hedge settlement receivables of $759 and $648 were included in accounts receivable at December 31, 2006 and September 30, 2007, respectively. There were no hedge settlements included in accounts receivable at December 31, 2005.

Index to Financial Statements

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, 2005 and 2006 approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2006, the carrying value of the 8¹/2% Senior Notes due 2015 approximates fair value. Based on market prices, at September 30, 2007, the fair value of the 8¹/2% Senior Notes and the 8⁷/8% Senior Notes were $303,875 and $303,875, respectively.

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.

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 15.9%, 14.3% and 11.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the years ended December 31, 2004, 2005 and 2006, respectively. If the Company were to lose a purchaser, we believe we could replace it with a substitute purchaser.

The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses or disposal of its oil and gas properties and related facilities. 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.

Index to Financial Statements

The activity incurred in the asset retirement obligation for the years ended December 31, 2005 and 2006 and the nine months ended September 30, 2007 is as follows:

Index to Financial Statements

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, 2006 are as follows:

Issuance of our 8¹/2% 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:

Index to Financial Statements

In connection with the issuance of the 8¹/2% Senior Notes, the Company capitalized $9,251 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 and $8,604 as of December 31, 2005 and 2006, respectively that are included in other assets. Amortization of $48 and $598 was charged to interest expense during the years ended December 31, 2005 and 2006, respectively, related to these costs.

Issuance of our 8⁷/8% Senior Notes due 2017. On January 18, 2007, the Company issued $325,000 of 8.875% Senior Notes due 2017 at a price of 99.178% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to reduce outstanding indebtedness under our revolving line of credit and for working capital.

Interest is payable on the Senior Notes semi-annually on February 1 and August 1 each year beginning August 1, 2007. The Senior Notes mature on February 1, 2017. On or after February 1, 2012, the Company, at its option, may redeem the Senior Notes at the following redemption prices plus accrued and unpaid interest: 104.49% after February 1, 2012, 102.96% after February 1, 2013, 101.48% after February 1, 2014, and 100% after February 1, 2015 and thereafter. Prior to February 1, 2012, 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 108.88%, plus accrued and unpaid interest.

The indenture governing the Senior Notes contains certain covenants which limit the Company’s ability to:

In connection with the issuance of our 8⁷/8% Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with

Index to Financial Statements

the Securities and Exchange Commission related to an offer to exchange the notes for other freely tradable notes and complete such exchange offer within 270 days of the issue date. If we fail to complete the exchange offer within 270 days after the issue date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

During September 2007, the Company determined that the exchange offer would not be completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, the Company accrued liquidated damages of $0.2 million during the three months ended September 30, 2007.

In connection with the issuance of the 8⁷/8% Senior Notes, the Company recorded a discount of $2,671 and capitalized $7,188 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized issuance costs of $6,875 as of September 30, 2007 that are included in other assets. Amortization of $42 and $114 was charged to interest expense during the three months ended September 30, 2007 related to the discount and issuance costs, respectively. Amortization of $118 and $313 was charged to interest expense during the nine months ended September 30, 2007 related to the discount and issuance costs, respectively.

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, excluding Pointe Vista Development, L.L.C. (“Pointe Vista”). Pointe Vista, a 100% owned subsidiary and Oklahoma Ethanol, a 66.67% owned subsidiary, have no significant operations or capitalization and are not restricted subsidiaries or guarantors of the notes.

Senior Notes at December 31, 2006 and September 30, 2007 consisted of the following:

Index to Financial Statements

Income tax expense differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:

Components of the deferred tax assets and liabilities are as follows at December 31:

Approximately $24,034 and $1,705 of the current deferred tax asset at December 31, 2005 and 2006, respectively, relates to the short-term derivative instruments. Additionally, approximately $23 and $54 of the current deferred tax asset relates to asset retirement obligations at December 31, 2005 and 2006, respectively. At December 31, 2005 and 2006, taxes receivable of $120 and $7, respectively, are included in accounts receivable.

Index to Financial Statements

The Company has federal net operating loss carryforwards of approximately $35,000 at December 31, 2006, which will begin to expire in 2008 if unused. At December 31, 2006, the Company has state net operating loss carryforwards of approximately $127,000, which will begin to expire in 2007. At December 31, 2006, approximately $83,000 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, 2006, the Company had tax percentage depletion carryforwards of approximately $3,964 which are not subject to expiration.

In accordance with Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information, we have two reportable operating segments. Our exploration and production segment and service company segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for finding and producing oil and natural gas. The service company segment is responsible for selling oilfield services and supplies. Management evaluates the performance of our segments based upon income before taxes. The service company was acquired during the second quarter of 2007, therefore, no segment information is provided for the three and nine months ended September 30, 2006.

In September 2006, Chesapeake Energy Corporation “Chesapeake” acquired a 31.9% beneficial interest in the Company through the sale of common stock. The Company participates in

Index to Financial Statements

ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings of $9,792 and $4,361, respectively for the year ended December 31, 2006 and $2,483 and $964, respectively for the three months ended September 30, 2007 and $5,863 and $3,289, respectively for the nine months ended September 30, 2007 on these properties. In addition, Chesapeake participates in ownership of properties operated by the Company. During the year ended December 31, 2006, the Company paid revenues and recorded joint interest billings of $1,809 and $2,556, respectively to Chesapeake. During the three months ended September 30, 2007, the Company paid revenues and recorded joint interest billings of $393 and $518, respectively to Chesapeake. During the nine months ended September 30, 2007, the Company paid revenues and recorded joint interest billings of $1,090 and $904, respectively. There were no significant amounts receivable or payable to Chesapeake at December 31, 2006 or September 30, 2007.

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 in cash together with the assumption of a loan of $262, 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 $328. Record title was taken in the name of the Company’s chief executive officer, who entered into a mortgage securing the loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral used 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 $38 through November 2005.

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 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. Under the original plan, 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. Effective January 1, 2007 the Company reduced the phantom unit vest period from the seventh anniversary of the award date to the fifth anniversary of the original award date. In accordance with SFAS No. 123(R) “Share Based Payments”, the reduction in the vesting period is accounted for as a modification to the plan and is accounted for on a prospective basis. The Company recorded additional deferred compensation expense of $417 during the nine months ended September 30, 2007 as a result of the modification.

Index to Financial Statements

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.

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.

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.

Compensation expense is recognized over the vesting period of the phantom units and is reflected in general and administrative expenses in the income statement. Such expense is calculated net of forfeitures estimated based on the Company’s historical and expected turnover rates. The Company recognized deferred compensation gain of $30 resulting in an increase in net income and expense of $702 resulting in a reduction in net income for the three months ended September 30, 2006 and 2007, respectively. The Company recognized deferred compensation expense of $130 and $1,392 resulting in a reduction in net income for the nine months ended September 30, 2006 and 2007, respectively.

Index to Financial Statements

A summary of the Company’s phantom unit activity as of December 31, 2006, and changes during the year ended September 30, 2007 is presented in the following table:

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 September 30, 2007.

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:

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 September 30, 2007, there was approximately $1,735 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 2.37 years.

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 wages. At December 31, 2004, 2005 and 2006, there were 207, 256 and 415 employees,

Index to Financial Statements

respectively, participating in the plan. Contributions recognized by the Company totaled $544, $682 and $883 for the years ended December 31, 2004, 2005 and 2006, respectively.

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 $990, $990, and $865 as of December 31, 2004, 2005, and 2006, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 7.25% at December 31, 2005 and 8.25% at December 31, 2006) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during 2004, 2005, or 2006.

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, 2004, 2005, and 2006 was $486, $327, and $394, respectively. Future minimum rental payments for the rental of equipment on oil and gas properties are approximately $595, $275 and $7 for the years ended December 31, 2007, 2008 and 2009, 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 $115 million and $125 million, with the Company having a 66.67% ownership interest. The Company expects Oklahoma Ethanol L.L.C. will receive between $69 million to $75 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 commence construction in 2008 with completion in 2010, and that its equity contribution will be approximately $30 million to $33 million.

We entered into an agreement to build a natural gas pipeline, a CO₂ pipeline, and compression facilities at an ethanol plant being constructed and operational in 2008. The construction of these pipelines and facilities and the related costs are contingent on certain events and are currently estimated to be a minimum of $2,200. We also have a long-term contract to purchase all of the CO₂ manufactured at the ethanol plant, if built. Based on estimated plant capacity, it is estimated that we will purchase approximately 4.2 Mmcf per day at variable contract prices over the ten-year contract term with the possibility of renewal.

Index to Financial Statements

per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, which is consistent with our current level. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

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.

At December 31, 2006, the Company had commitments to re-enter, drill or acquire certain oil and gas properties. The estimated costs for these commitments was approximately $6,902.

On March 1, 2007, one of our unrestricted subsidiaries entered into an agreement with the Commissioners Land Office of the State of Oklahoma to acquire two parcels of land and improvements in conjunction with a real estate redevelopment project. The cost of the first parcel is $10,200 and is scheduled to close no later than December 31, 2007 subject to production of clear title. Payments are $5,600 at closing, three annual installments of $1,000 and a final payment of $1,600. The cost of the second parcel is $4,400, subject to satisfaction of certain conditions and is payable in two annual installments of $2,200 on the fifth and sixth anniversary dates of the close of the first parcel.

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.

Pursuant to the securities purchase agreement dated as of September 16, 2006, as amended, relating to the acquisition of Calumet, the Company recorded a receivable of $14,406 due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, the Company received a communication from the sellers disputing the calculation of the purchase price adjustment. The Company believes the receivable was calculated in accordance with the securities purchase agreement and intends to diligently defend its position. On September 13, 2007, the Company filed a petition in the District Court of Tulsa County, State of Oklahoma, against John Milton Graves Trust u/t/a 6/11/2004, et al, seeking a declaratory judgement confirming this position. As of September 30, 2007, the recorded receivable was $14,406, of which $9,793 is in dispute, and was recorded in accounts receivable on the consolidated balance sheet.

On September 27, 2006, the Company effected a 775-for-1 stock split in the form of a stock dividend to shareholders of record as of September 26, 2006. As a result of the split, 774,000 additional shares were issued and retained earnings was reduced by $7. All share and per share amounts for all periods presented have been adjusted to reflect this stock split.

Index to Financial Statements

On September 29, 2006, the Company closed the sale of an aggregate of 102,000 shares of Chaparral’s common stock to Chesapeake Energy Corporation for an aggregate cash purchase price of $102,000. Proceeds from the sale after commissions and expenses were approximately $100,900 and are being used for general corporate and working capital purposes and acquisition of oil and gas properties.

Cash dividends of $3,409 and $1,049 were paid during the years ended December 31, 2005 and 2006, respectively. Dividends of $350 were paid on a quarterly basis from January 1, 2005 through September 30, 2006 and a one-time dividend of $2,000 was paid on February 1, 2005. Cash dividend of $1,050 were paid during the nine months ended September 30, 2006. No dividends were paid during the nine months ended September 30, 2007.

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:

The average depreciation, depletion and amortization rate per equivalent unit of production was $0.77, $1.09 and $1.45 for the years ended December 31, 2004, 2005 and 2006, respectively.

Oil and gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and exploratory wells in progress. Of the $18,299 of unproved property costs at December 31, 2006 being excluded from the amortization base, $1,415, $6,500 and $10,211 were incurred in 2004, 2005 and 2006, respectively, and $173 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.

Index to Financial Statements

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.

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, 2004, 2005 and 2006 are as follows:

Index to Financial Statements

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.

The Company believes that, in reviewing the information that follows, the following factors should be taken into account:

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, “Derivative 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.

Index to Financial Statements

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

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 $29,332, $44,935, and $6,729 in 2004, 2005 and 2006, respectively.

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

Index to Financial Statements

Average prices in effect at December 31, 2004, 2005 and 2006 used in determining future net revenues related to the standardized measure calculation are as follows:

During 2007 the Company determined that certain of its proved undeveloped (PUD) reserves relating to its tertiary recovery projects did not meet the criteria of proved reserves as defined by Rule 4-10(a) of Regulation S-X. As a result, the Company recorded a downward revision of 62,988 MMcfe of estimated proved reserves at December 31, 2006. No other years were affected by the revision. Quantities of estimated proved reserves are used in determining financial statement amounts, including ceiling test charges and depletion, depreciation, and amortization (DD&A). The revision of our historical estimated reserves did not have a significant impact on the Company’s financial statements, and therefore did not require a restatement. The Company has restated the disclosures about oil and gas activities to reflect the impact of the revision.

Our reserve restatement resulted in the following revisions to our estimated proved reserves as of December 31, 2006:

Effective November 1, 2007, the borrowing base on the Company’s revolving line of credit was increased to $525.0 million. Under the agreement the Company has committed to hedging 80% of its internally estimated PDP crude oil production for 2008, 2009 and 2010 and 75% and 25% of its internally estimated PDP natural gas production for 2008 and 2009, respectively.

Index to Financial Statements

We have audited the combined balance sheets of Calumet Oil Company and Subsidiary and JMG Oil & Gas, LP (collectively, the “Company”), as of December 31, 2005 and September 30, 2006 and the related combined statements of income, stockholders’ equity and partners’ capital and cash flows for the years ended December 31, 2004 and 2005 and the nine months ended September 30, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005 and September 30, 2006 and the results of their operations and their cash flows for the years ended December 31, 2004 and 2005 and the nine months ended September 30, 2006, in conformity with accounting principles generally accepted in the United States of America.

Index to Financial Statements

During the years ended December 31, 2004 and 2005 and the nine months ended September 30, 2006, the Company recorded an asset and related liability of $80, $4,652, and $130 associated with the asset retirement obligation on acquisition and/or development of oil and gas properties.

Index to Financial Statements

Calumet Oil Company (“Calumet”) was organized in the state of Oklahoma on October 11, 1956. On August 18, 2004, JMG Oil & Gas, LP (“JMG”), an Oklahoma limited partnership, was organized and certain assets and liabilities of oil and gas producing activities were transferred from the John Milton Graves Trust to JMG. J.M. Graves L.L.C., an Oklahoma limited liability company, owned the general partner interest in JMG, and such general partner interest was its only asset. The accompanying financial statements include the assets, liabilities and results of operations as though that transfer occurred on December 31, 2003. Calumet and JMG are primarily engaged in the production and operation of oil and gas properties. Properties are located primarily in Oklahoma and Texas.

A summary of the significant accounting policies applied in the preparation of the accompanying combined financial statements follows.

The accompanying combined financial statements include the accounts of Calumet Oil Company and its wholly owned subsidiary, Calumet-Eakin Gas Company, L.L.C. (“Eakin”) and JMG (collectively, “the Company”), both of which are under common control. All intercompany transactions and balances have been eliminated in combination and consolidation.

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, accounts receivable asset retirement obligations and others, and are subject to change.

Index to Financial Statements

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, 2005 and September 30, 2006, the Company has cash and cash equivalents of approximately $24,280 and $18,946, respectively, at two financial institutions.

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

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. 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, 2004 and 2005 and the nine months ended September 30, 2006 were $7, $8, and $55, respectively. Accounts receivable consisted of the following:

Inventories consists of equipment used in developing oil and gas properties of $179 and $127 at December 31, 2005 and September 30, 2006, respectively and fuel of $32 and $37 at December 31, 2005 and September 30, 2006, respectively. Equipment inventory is carried at the lower of cost or market using the specific identification method. Fuel inventories are carried at the lower of cost or market.

Index to Financial Statements

Investments in unaffiliated debt and equity securities that have a readily determinable fair value are classified as “trading securities” as it is management’s intent to only hold them for the near term. The Company reevaluates the classification of investments in unaffiliated equity securities at each balance sheet date. The carrying value of trading securities is adjusted to fair value as of each balance sheet date. Unrealized holding gains are recognized in other income and unrealized holding losses are recognized in other expense during the period in which changes in fair value occur. Trading gains and losses related to investments still held are as follows:

Property and equipment and betterments of such equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently.

The Company 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.

Index to Financial Statements

property abandonment costs, net of equipment salvage values) are amortized similarly by field based on estimates of proved developed 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 Company 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 Company’s estimated future cash flows and reserve quantities are based upon the latest forward pricing curves based on the respective period end reserve report. 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 expense. Unproved properties which are not individually significant are periodically assessed for impairment on a field-by-field basis using the Company’s drilling history and lease period.

The Company has cash balances classified as restricted when the cash is restricted as to withdrawal or usage. The restricted cash represents amounts held in escrow for plugging and abandonment obligations which were incurred with the acquisition of certain properties in 1995. The Company is entitled to make quarterly withdrawals from the escrow account as reimbursement for actual plugging and abandonment expenses incurred on the inactive well bores, provided that written documentation has been provided. The balance is not intended to reflect the Company’s total future financial obligation for the plugging and abandonment of these wells.

Index to Financial Statements

Calumet Oil Company has elected under the Internal Revenue Code to be an S corporation. In lieu of corporation income taxes, the shareholders of an S corporation are taxed on their proportionate share of Calumet’s taxable income. Income taxes on net income of JMG are payable by the partners. Accordingly, no provision has been made for federal or state income taxes in the combined financial statements.

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.

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 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 Company’s obligation for natural gas taken by its purchasers which exceeds the Company’s ownership interest of the well’s total production. There were no significant imbalances at December 31, 2005 or September 30, 2006.

The Company uses swaps to reduce the effect of fluctuations in crude oil prices. The Company 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 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. None of the Company’s derivative contracts qualified for hedge accounting under the terms of SFAS No. 133.

SFAS No. 143, Accounting for Asset Retirement Obligations 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 combined statements of income. The Company’s asset retirement obligations relate to estimated

Index to Financial Statements

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.

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, 2005 and September 30, 2006 the Company has not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon the financial position, operating results, or cash flows of the Company.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not believe that this new standard will have a material effect on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently reviewing this new standard to determine its effects, if any, on our financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” an amendment to SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106.” SFAS No. 158 requires an employer to recognize a benefit plan’s funded status in its statement of financial position, measure a benefit plan’s assets and obligations as of the end of the employer’s fiscal year and recognize the changes in the benefit

Index to Financial Statements

plan’s funded status in other comprehensive income in the year in which the changes occur. SFAS No. 158’s requirement to recognize the funded status of a benefit plan and the new disclosure requirements are effective as of the end of the fiscal year ending after December 15, 2006. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008. We do not believe that this new standard will have a material effect on our financial position, results of operations or cash flows.

The Securities and Exchange Commission (SEC) issued Staff Accounting Bulleting No. 108 (“SAB 108”), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” in September 2006. SAB 108 provides guidance regarding the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of materiality assessments. The method established by SAB 108 requires each of the Company’s financial statements and the related financial statement disclosures to be considered when quantifying and assessing the materiality of the misstatement. The provisions of SAB 108 will apply to the Company’s financial position and results of operations for the fiscal year ended December 31, 2006. The Company does not expect to record an adjustment from the implementation of SAB 108.

Index to Financial Statements

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 instruments. The Company’s derivative instruments were comprised solely of 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 to or from the counterparty.

The Company accounts for derivative financial instruments in accordance with SFAS 133. During 2004, 2005, and 2006, none of the derivative contracts qualified for hedge accounting under the terms of SFAS 133. Accordingly, the derivative instruments are recorded as an asset or liability on the balance sheet at fair value and the change in the fair value is recorded in non-hedge derivative gains (losses) in the combined statements of income. The estimated fair value of derivative instruments was an asset of $1,733 at December 31, 2005 and a liability of $4,381 as of September 30, 2006.

The carrying values of these instruments are equal to the estimated fair values. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward market price at the determination date considering the time value of money. 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.

Index to Financial Statements

The Company’s financial instruments include cash and cash equivalents, trading securities, receivables, payables and derivative instruments. The carrying values of items comprising current assets and current liabilities approximate fair value due to the short-term nature of these instruments.

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. The counterparty to the Company’s derivative instruments consists of the financial institution where the Company maintains its line of credit 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 three purchasers accounted for 82%, 90% and 73% of total oil and natural gas revenues during the years ended December 31, 2004 and 2005 and the nine months ended September 30, 2006, respectively. If the Company were to lose a purchaser, we believe we could identify a substitute purchaser.

The Company purchases oilfield goods, services and equipment from Green Country Supply, Inc. (“Green Country”), an entity with common owners as the Company. During the years ended December 31, 2004 and 2005 and the nine months ended September 30, 2006, purchases from Green Country totaled $7,770, $10,446, and $7,538, respectively.

Index to Financial Statements

As of December 31, 2005 and September 30, 2006, the accounts payable-related party consisted of $1,311 and $1,258, respectively, of cash amounts from Green Country that were transferred for cash management purposes and $567 and $647 of amounts outstanding related to purchases from Green Country.

During 2006, the Company sold certain properties to HB&R Oil Co, LLC (“HB&R”) for $464. HB&R is wholly owned by a shareholder and director of the Company. All accounts receivable related to the sale were received in October 2006. Other related party accounts receivable as of December 31, 2005 and September 30, 2006 consists of $377 and $297, respectively, from Green Country and $314 and $106, respectively, from certain owners for joint interest billings.

The Company provides a 401(k) retirement plan for all full-time employees with at least one month of service. The Company provides an annual discretionary match of employee contributions which is not required by the plan. The Company has no additional obligation related to the plan. At December 31, 2004 and 2005, and September 30, 2006, there were 263, 272 and 248 employees, respectively, participating in the plan. Contributions recognized by the Company totaled $118, $132 and $122 for the years ended December 31, 2004 and 2005, and the nine months ended September 30, 2006, respectively.

On January 28, 2005, the Company was recapitalized by authorizing 20,000 shares of $1 par value Class A voting stock of which 20,000 are issued and outstanding and authorizing 30,000,000 shares of $.001 par value Class B nonvoting stock of which 20,000,000 shares are issued and outstanding. All stock outstanding prior to January 28, 2005 was cancelled.

The Company has a $100,000 revolving credit agreement with a maximum borrowing base of $66,000. The agreement allows the Company a choice of an interest rate based on Bank of Oklahoma prime or the London Interbank Offered Rate (“LIBOR”). The choice of interest rates determines the interest payment due date. The note is secured by oil and gas properties and certain related equipment and oil and gas inventories. There were no borrowings under the credit agreement at December 31, 2005 or September 30, 2006.

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 combined financial position or combined results of operations.

Index to Financial Statements

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:

The estimate of proved reserves and related valuations were based upon the report of Lee Keeling and Associates, Inc., independent petroleum and geological engineers, 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.

Index to Financial Statements

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 ending December 31, 2004 and 2005 and the nine months ending September 30, 2006 is as follows:

The Company believes that, in reviewing the information that follows, the following factors should be taken into account:

Index to Financial Statements

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 derivative positions (see Note 5, “Derivative 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. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

Index to Financial Statements

Average prices in effect at December 31, 2004 and 2005 and September 30, 2006 used in determining future net revenues related to the standardized measure calculation are as follows:

During 2007, the Company determined that certain of its proved undeveloped (PUD) reserves relating to its tertiary recovery projects did not meet the criteria of proved reserves as defined by Rule 4-10(a) of Regulation S-X. As a result, the Company recorded a downward revision of 77,832 MMcfe of estimated proved reserves at December 31, 2003. Quantities of estimated proved reserves are used in determining financial statement amounts, including ceiling test charges and depletion, depreciation, and amortization (DD&A). The revision of our historical estimated reserves did not have a significant impact on the Company’s financial statements, and therefore did not require a restatement. The Company has restated the disclosures about oil and gas activities to reflect the impact or revision.

Index to Financial Statements

Our reserve restatement resulted in the following revisions to our estimated proved reserves for the years ending December 31, 2004 and 2005 and the nine months ending September 30, 2006 is as follows:

On October 31, 2006, all of the outstanding capital stock of Calumet, all of the membership interests of its affiliates and all of the limited partnership interests of JMG were acquired by Chaparral Energy, Inc. for $500 million. Also, on October 31, 2006 and in connection with the sale, the Company awarded and paid a $10 million severance bonus to its employees and directors.

Index to Financial Statements

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.

Index to Financial Statements

Years ended December 31, 2002, 2003, and 2004 and for the nine-month period ended September 30, 2005

Index to Financial Statements

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:

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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.

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.

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.

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.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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.

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.

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 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.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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.

Oil and natural gas revenue is recognized when the product is delivered to the purchaser.

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.

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.

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, 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.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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:

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

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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.

Certain reclassifications have been made to prior year amounts to conform to current year presentation.

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 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

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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:

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.

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 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.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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:

Net capitalized costs related to the Company’s oil and gas producing activities are summarized as follows:

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.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

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:

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

The Partnership believes that, in reviewing the information that follows, the following factors should be taken into account:

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.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

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 $19,908, $24,647 and $22,272 in 2002, 2003, and 2004, respectively.

Index to Financial Statements

(Information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited)

The changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are as follows:

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:

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 8¹/2% 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.

Index to Financial Statements

Chaparral Energy, Inc. is a Delaware corporation. Section 145 of the Delaware General Corporation Law authorizes a court to award, or a corporation’s board of directors to grant, indemnity under certain circumstances to directors, officers employees or agents in connection with actions, suits or proceedings, by reason of the fact that the person is or was a director, officer, employee or agent, against expenses and liabilities incurred in such actions, suits or proceedings so long as they acted in good faith and in a manner the person reasonable believed to be in, or not opposed to, the best interests of the company, and with respect to any criminal action if they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys’ fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate.

As permitted by Delaware law, our certificate of incorporation includes a provision that eliminates the personal liability of our directors to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

As permitted by Delaware law, our certificate of incorporation provides that we are required to indemnify our directors and officers to the fullest extent permitted by Delaware law.

The indemnification provisions in our certificate of incorporation may be sufficiently broad to permit indemnification of our directors and officers for liabilities arising under the Securities Act.

Under Delaware law, corporations also have the power to purchase and maintain insurance for directors, officers, employees and agents.

Prior to the closing of the offering, it is contemplated that Chaparral and its subsidiaries will be covered by liability insurance policies which indemnify their directors and officers against loss

Index to Financial Statements

arising from claims by reason of their legal liability for acts as such directors, officers, or trustees, subject to limitations and conditions as set forth in the policies.

The foregoing discussion of our certificate of incorporation and Delaware law is not intended to be exhaustive and is qualified in its entirety by such certificate of incorporation or law.

We have entered into indemnification agreements with Mark A. Fischer, Charles A. Fischer, Jr., Joseph O. Evans and Robert W. Kelly II. 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 will 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 will 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 will also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee will, in turn, be 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 will not be obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

Under the Delaware Limited Liability Company Act, a limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

The Agreement of Limited Liability Company of CEI Acquisition, L.L.C. provides that a member shall not be liable to CEI Acquisition, L.L.C. for any act or omission based upon errors of judgment or other fault in connection with the business or affairs of CEI Acquisition, L.L.C. if such member’s conduct does not constitute gross negligence or willful misconduct. Furthermore, the Agreement of Limited Liability Company of CEI Acquisition, L.L.C. provides that a member shall be indemnified and held harmless by CEI Acquisition, L.L.C., to the fullest extent permitted by law, from and against any and all losses, claims, damages and settlements arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which the member is involved, as a party or otherwise, by reason of the management of the affairs of CEI Acquisition, L.L.C., provided that no member shall be entitled to indemnification for such losses, claims, damages and settlements arising as a result of the gross negligence or willful misconduct of such member.

Index to Financial Statements

Under the Oklahoma Limited Liability Company Act, a limited liability company may (i) limit or eliminate the personal liability of a manager for monetary damages for breach of any duty under the Oklahoma Limited Liability Company Act or (ii) provide for indemnification of a manager for judgments, settlements, penalties, fines or expenses incurred in any proceeding because such manager is or was a manager of the limited liability company, except, in either case, for any breach of a manager’s duty of loyalty or any acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law.

The Operating Agreements of each of Chaparral Energy, L.L.C., Chaparral CO₂, L.L.C., Chaparral Real Estate, L.L.C., Chaparral Resources, L.L.C., Noram Petroleum, L.L.C., and Triumph Tools Supply, L.L.C., which are Oklahoma limited liability companies, provide indemnification and eliminate liability for each manager or officer of such limited liability company from any and all monetary damages, claims, demands and actions of every kind and nature whatsoever which may arise by reason of a manager’s or officer’s performance of his or her duties and responsibilities, except (i) for liabilities arising as a result of a breach of the manager’s or officer’s duty of loyalty to such limited liability company or its members, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) for any transaction from which the manager or officer derived an improper personal benefit and (iv) with respect to indemnification, a breach of any provision of such limited liability company’s Operating Agreement.

Sections 8.101 through 8.103 of the Texas Business Organizations Code provide that a company may indemnify an officer or director who was, is, or is threatened to be made a respondent in a proceeding, whether civil, criminal, administrative, arbitrative, or investigative, because the person is or was a director, officer, employee, or agent of the company, or is or was serving at the request of the company in the same or another capacity in another corporation or business association, against judgments, penalties, fines, settlements and reasonable expenses actually incurred if it is determined that the person: (i) acted in good faith, (ii) reasonably believed (a) in the case of conduct in his official capacity, that his conduct was in the best interests of the company, or (b) in any other case, that his conduct was not opposed to the company’s best interest, and (iii) in the case of a criminal proceeding, did not have reasonable cause to believe his conduct was unlawful; provided that, if the person is found liable to the company or is found liable on the basis that personal benefit was improperly received by the person, the indemnification (i) is limited to reasonable expenses actually incurred by the person in connection with the proceeding (ii) does not include a judgment, a penalty, a fine, and an excise or similar tax, including an excise tax assessed against the person with respect to an employee benefit plan, and (iii) may not be made in respect of any proceeding in which the person shall have been found liable for willful or intentional misconduct in the performance of his duty to the company, breach of the person’s duty of loyalty owed to the company, or an act or omission not committed in good faith that constitutes a breach of a duty owed by the person to the company.

The Operating Agreement of CEI Pipeline, L.L.C. provides indemnification to the maximum extent permitted by law, of each manager, such manager’s affiliates, and the employees and agents of

Index to Financial Statements

the company (each, an “Indemnitee”) from and against any and all losses, claims, demands, costs, damages, liabilities, joint and several, expenses of any nature (including attorneys’ fees and disbursements), judgments, fines, settlements, penalties and other expenses actually and reasonably incurred by the Indemnitee in connection with any and all claims, demands, actions, suits, or proceedings, civil, criminal, administrative or investigative, in which the Indemnitee may be involved, or threatened to be involved, as a party or otherwise, by reason of the fact that the Indemnitee is or was a manager of the company or is or was an employee or agent of the company, including affiliates of the foregoing, arising out of or incidental to the business of the company, provided: (a) the Indemnitee’s conduct did not constitute willful misconduct or recklessness; (b) the action is not based on breach of the operating agreement; (c) the Indemnitee acted in good faith and in a manner such Indemnitee reasonably believed to be in, or not opposed to, the best interests of the company and within the scope of such Indemnitee’s authority; and (d) with respect to a criminal action or proceeding, the Indemnitee had no reasonable cause to believe such Indemnitee’s conduct was unlawful.

Index to Financial Statements

(a)(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if the registration statement is on Form S-3, Form S-8 or Form F-3, and the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the Commission by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the registration statement.

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement

Index to Financial Statements

relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(b) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

(c) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in this registration statement when it became effective.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Index to Financial Statements

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement on Form S-4 to be signed on its behalf by the undersigned, thereunder duly authorized, in Oklahoma City, Oklahoma on January 3, 2008.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Index to Financial Statements

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.


Exact Name of Additional Registrant as Specified in its Charter	State or Other Jurisdiction of Incorporation or Organization	Primary Standard Industrial Classification Code Number	I.R.S. Employer Identification No.
Chaparral Real Estate, L.L.C.(1)	Oklahoma	1311	73-1591655
Chaparral Resources, L.L.C.(1)	Oklahoma	1311	73-1591710
Chaparral CO₂, L.L.C.(1)	Oklahoma	1311	73-1591656
Noram Petroleum, L.L.C.(1)	Oklahoma	1311	73-1435548
Chaparral Energy, L.L.C.(1)	Oklahoma	1311	73-1320941
CEI Pipeline, L.L.C.(1)	Texas	1311	20-5396877
CEI Acquisition, L.L.C.(1)	Delaware	1311	20-3551817
Green Country Supply, Inc.(1)	Oklahoma	1311	73-0802723


	2003		2004		2005			2006

Purchases of minerals in place		50,515		62,238		173,176			354,004
Extensions and discoveries		12,766		34,004		22,531			16,736
Revisions		102		14,535		(7,516	)		(56,423	)
Improved recoveries		8,202		39,722		20,262			6,653

Total reserve additions		71,585		150,499		208,453			320,970

Costs incurred	$	56,962	$	96,031	$	333,038		$	667,137
Changes in future development costs		20,494		121,938		154,042			236,700

Total costs incurred	$	77,456	$	217,969	$	487,080		$	903,837

Three-year average fully developed FD&A cost ($/Mcfe)					$	1.82		$	2.37


(Dollars in thousands)	As of September 30, 2007

Cash and cash equivalents	$	15,021


Long-term debt, including capital leases and current maturities(1):
Credit Agreement(2)		430,000
Other		17,884
8⁷/8% Senior Notes due 2017		325,000
8¹/2% Senior Notes due 2015		325,000
Discount on Senior Notes		(2,553	)

Total debt		1,095,331

Stockholders’ equity:
Common stock, $.01 par value; 877,000 shares issued and outstanding		9
Additional paid-in capital		100,918
Retained earnings		82,171
Accumulated other comprehensive loss, net of taxes		(25,175	)

Total stockholders’ equity		157,923

Total capitalization	$	1,253,254


(Dollars in thousands)	Year ended December 31, 2006

Historical interest expense	$	45,246
Interest expense resulting from the issuance of the 8⁷/8% Senior Notes, due 2017		28,607
Reduction in interest expense of the revolving credit agreement from the application of proceeds from the private equity sale		(4,932	)
Interest expense resulting from additional credit agreement borrowings for the Calumet acquisition		3,961
Amortization of the $7,500 deferred financing costs related to the restated credit agreement		1,875
Amortization of the deferred financing costs and accretion of discount related to the issuance of the 8⁷/8% Senior Notes, due 2017		1,017

Total pro forma interest expense	$	75,774


	Three months ended September 30,			Percentage Change
	2006	2007		Percentage Change


Oil and gas sales (dollars in thousands)
Oil	$27,533	$	67,577	145.4%
Gas	32,095		30,988	(3.4)%

Total	$59,628	$	98,565	65.3%

Production
Oil (MBbls)	416		926	122.6%
Gas (MMcf)	5,109		5,053	(1.1)%

MMcfe	7,605		10,609	39.5%

Average sales prices (excluding hedging)
Oil per Bbl	$ 66.19	$	72.98	10.3%
Gas per Mcf	6.28		6.13	(2.4)%
Mcfe	7.84		9.29	18.5%


		Page
Special cautionary statement regarding forward-looking statements		ii
Prospectus summary		1
Risk factors		23
Ratio of earnings to fixed charges		38
Use of proceeds		39
Capitalization		40
Unaudited pro forma financial data		41
Selected consolidated financial data		44
Management’s discussion and analysis of financial condition and results of operations		46
Business and properties		73
Management		94
Principal stockholders		112
Certain relationships and related transactions		113
Description of certain indebtedness		117
The exchange offer		122
Description of the new notes		134
Global securities; book-entry system		196
Material United States federal income tax considerations		200
Plan of distribution		201
Legal matters		202
Experts		202
Independent petroleum engineers		202
Where you can find more information		202
Glossary of terms		A-1
Index to financial statements		F-1


(Dollars in thousands)	Chaparral historical			Calumet historical			Adjustments (Note 2)			Pro forma

Revenues
Oil and gas sales	$	249,180		$	90,159			—		$	339,339
Loss on oil and gas hedging activities		(4,166	)		—			—			(4,166	)

Total revenues		245,014			90,159			—			335,173


Costs and expenses
Lease operating		71,663			25,937			—			97,600
Production tax		18,710			6,884			—			25,594
Dry hole and abandonment		—			129		$	(129	)(a)		—
Depreciation, depletion and amortization		52,299			3,623			13,789	(b)		69,711
Impairment of long-lived assets		—			996			(996	)(c)		—
General and administrative		14,659			1,795			—			16,454

Total costs and expenses		157,331			39,364			12,664			209,359

Operating income		87,683			50,795			(12,664	)		125,814

Non-operating income (expense)
Interest expense		(45,246	)		—			(30,528	)(d)		(75,774	)
Non-hedge derivative losses		(4,677	)		(3,820	)		—			(8,497	)
Other income		792			2,239			(420	)(e)		2,611

Net non-operating expense		(49,131	)		(1,581	)		(30,948	)		(81,660	)

Income before income taxes and minority interest		38,552			49,214			(43,612	)		44,154

Income tax expense		14,817			—			2,153	(f)		16,970
Minority interest		(71	)		—			—			(71	)

Net income	$	23,806		$	49,214		$	(45,765	)	$	27,255


	Year Ended December 31,															Nine months ended September 30,
(Dollars in thousands)	2002			2003			2004			2005			2006			2006			2007
																(unaudited)

Cash flow data:
Net cash provided by operating activities	$	17,480		$	32,541		$	46,870		$	55,744		$	89,198		$	72,160		$	79,807
Net cash used in investing activities		(27,505	)		(55,213	)		(92,141	)		(325,068	)		(703,848	)		(165,211	)		(184,198	)
Net cash provided by financing activities		8,921			26,146			54,061			257,080			621,855			194,178			110,609


	As of December 31,															As of September 30, 2007 (unaudited)
(Dollars in thousands)	2002			2003			2004			2005			2006			As of September 30, 2007 (unaudited)

Financial position data:
Cash and cash equivalents	$	1,578		$	5,052		$	13,842		$	1,598		$	8,803		$	15,021
Total assets		142,919			211,086			308,827			647,379			1,331,435			1,472,209
Total debt		91,780			118,355			176,622			446,544			976,272			1,095,331
Retained earnings		20,420			30,977			48,692			58,126			80,883			82,171
Accumulated other comprehensive loss, net of income taxes		(3,733	)		(4,900	)		(12,107	)		(47,967	)		(3,946	)		(25,175	)
Total equity		16,688			26,078			36,586			10,167			177,864			157,923
Cash dividends per common share		—			—			—		$	4.40		$	1.35			—


	Three months ended September 30,		Percentage Change
	2006(1)	2007	Percentage Change

Mid Continent	4,473	7,023	57.0%
Permian	1,271	1,586	24.8%
Ark-La-Tex	447	475	6.3%
North Texas	282	402	42.6%
Rockies	326	246	(24.5)%
Gulf Coast	806	877	8.8%

Totals	7,605	10,609	39.5%


	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge		Hedged to Non-Hedged Price

Oil (per Bbl):
Three months ended September 30, 2006	$	66.19	$	50.41	76.2%
Three months ended September 30, 2007		72.98		62.75	86.0%

Gas (per Mcf):
Three months ended September 30, 2006	$	6.28	$	7.81	124.4%
Three months ended September 30, 2007		6.13		7.16	116.8%


	Amount					Per Mcfe
	Three months ended September 30,				Percent Change	Three months ended September 30,				Percent Change
(dollars in thousands)	2006		2007		Percent Change	2006		2007		Percent Change

Lease operating expenses	$	15,719	$	27,033	72.0%	$	2.07	$	2.55	23.2%
Production taxes		4,324		6,803	57.3%		0.57		0.64	12.3%
Depreciation, depletion and amortization		11,967		22,364	86.9%		1.57		2.11	34.4%
General and administrative		3,005		5,727	90.6%		0.40		0.54	35.0%


	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge		Hedged to Non-Hedged Price

Oil (per Bbl):
Year ended December 31, 2005	$	53.76	$	36.43	67.8%
Year ended December 31, 2006		61.65		47.32	76.8%

Gas (per Mcf):
Year ended December 31, 2005	$	7.41	$	4.82	65.0%
Year ended December 31, 2006		6.29		7.39	117.5%


	Amount					Per Mcfe
	Year ended December 31,				Percent Change	Year ended December 31,				Percent Change
(dollars in thousands)	2005		2006		Percent Change	2005		2006		Percent Change

Lease operating expenses	$	42,147	$	71,663	70.0%	$	1.66	$	2.21	33.1%
Production taxes		14,626		18,710	27.9%		0.58		0.58	0.0%
Depreciation, depletion and amortization		31,423		52,299	66.4%		1.24		1.61	29.8%
General and administrative		9,808		14,659	49.5%		0.39		0.45	15.4%


(Dollars in thousands)	For the year ended December 31, 2006(1)		Percent of total

Mid-Continent(2)	$	547,873	82.1%
Permian Basin		49,510	7.4%
Ark-La-Tex		5,194	0.8%
North Texas		17,154	2.6%
Rocky Mountains		15,804	2.4%
Gulf Coast		31,602	4.7%
	$	667,137	100.0%


(Dollars in thousands)	For the year ended December 31, 2006(1)		For the nine months ended September 30, 2007		2007 budgeted capital expenditures

Development activities:
Developmental drilling	$	127,280	$	66,121	$	122,000
Enhancements		31,036		37,227		30,000
Tertiary recovery		12,671		10,291		20,000

Acquisitions:
Proved properties(2)(3)		484,404		37,741		25,000
Unproved properties		4,731		5,163		5,000
Exploration activities		7,015		9,295		10,000
Total	$	667,137	$	165,838	$	212,000


(Dollars in thousands)	2007 drilling capital expenditures		Percent of total

Mid-Continent	$	99,000	65.0%
Permian Basin		31,000	20.4%
Ark-La-Tex		1,000	0.7%
North Texas		10,000	6.6%
Rocky Mountains		1,000	0.7%
Gulf Coast		10,000	6.6%

	$	152,000	100.0%


(Dollars in thousands)	December 31, 2006			September 30, 2007

Current assets per GAAP	$	91,863		$	121,336
Plus—Availability under Credit Agreement		112,136			68,326
Less—Deferred tax asset on derivative instruments and asset retirement obligation		(847	)		(5,687)
Less—Short-term derivative instruments		(7,599	)		—

Current assets as adjusted	$	195,553		$	183,975

Current liabilities per GAAP	$	104,255		$	122,970
Less—Short-term derivative instruments		(12,376	)		(17,728)
Less—Short-term asset retirement obligation		(749	)		(749)

Current liabilities as adjusted	$	91,130		$	104,493

Current ratio for loan compliance		2.15			1.76


(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	$	47,020	$	731,040	$	—	$	—	$	778,060
Senior Notes, including estimated interest expense		27,625		82,875		82,875		380,250		573,625
Other long-term notes—including estimated interest expense		4,299		11,063		1,046		178		16,586
Capital leases—including estimated interest		176		171		—		—		347
Operating leases		595		282		—		—		877
Abandonment obligations		749		2,247		2,247		22,883		28,126
Derivative obligations		12,376		627		866		—		13,869
Drilling obligation		1,897		—		—		—		1,897
Preferential purchase right		5,005		—		—		—		5,005

Total	$	99,742	$	828,305	$	87,034	$	403,311	$	1,418,392


	Natural Gas basis protection swaps		Natural Gas Swaps				Crude Oil Swaps
	Non-hedge		Hedge				Hedge		Non-hedge
	Volume MMcf	Weighted average fixed price to be received	Volume MMcf	Weighted average fixed price to be received	Percent of PDP production hedged(1)		Volume MBbl	Weighted average fixed price to be received	Volume MBbl	Weighted average fixed price to be received		Percent of PDP production(1)(2)

4Q 2007	2,220	1.02	3,900	8.04	71.9	%	603	63.84	—		—	67.2	%
1Q 2008	2,070	1.16	960	10.07	18.7	%	543	68.02	60	$	67.48	70.4	%
2Q 2008	2,220	0.81	870	8.10	17.9	%	513	67.85	60		67.63	69.2	%
3Q 2008	2,220	0.81	610	8.14	13.2	%	508	68.05	60		67.64	70.7	%
4Q 2008	2,120	0.90	450	8.72	10.2	%	472	68.58	74		67.41	69.8	%
1Q 2009	2,070	0.92	—	—	—		402	67.84	111		67.15	67.3	%
2Q 2009	540	0.82	—	—	—		402	67.44	90		66.94	68.7	%
3Q 2009	—	—	—	—	—		402	67.02	90		66.57	70.3	%
4Q 2009	—	—	—	—	—		402	66.61	90		66.18	72.0	%
1Q 2010	—	—	—	—	—		366	66.34	102		65.80	71.4	%
2Q 2010	—	—	—	—	—		366	66.03	90		65.47	71.2	%
3Q 2010	—	—	—	—	—		366	65.57	90		65.10	72.9	%
4Q 2010	—	—	—	—	—		366	65.20	90		64.75	74.4	%
1Q 2011	—	—	—	—	—		309	64.40	99		64.24	67.8	%
2Q 2011	—	—	—	—	—		309	64.06	90		63.93	67.5	%
3Q 2011	—	—	—	—	—		309	63.71	90		63.61	68.7	%
4Q 2011	—	—	—	—	—		309	63.33	90		63.30	70.2	%

	13,460		6,790				6,947		1,376


	Identified proved undeveloped drilling locations	Identified additional potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net

Mid-Continent	571	1,609	367,476	37,460
Permian Basin	65	807	50,518	17,883
Ark-La-Tex	6	18	14,190	—
North Texas	36	99	16,286	763
Rocky Mountains	56	73	13,995	9,256
Gulf Coast	7	41	45,503	9,139

Total	741	2,647	507,968	74,501


	Proved reserves as of December 31, 2006						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, 2006	Year ended December 31, 2006	Nine months ended September 30, 2007

Mid-Continent	73,312	251,293	`691,165	76.4%	$	1,087.4	53.3	76.8	72.3
Permian Basin	6,039	58,233	94,467	10.4%		170.6	15.1	15.1	17.6
Ark-La-Tex	1,077	18,919	25,381	2.8%		47.9	4.7	4.7	5.0
North Texas	2,324	5,008	18,952	2.1%		38.4	3.1	3.1	3.8
Rocky Mountains	3,563	7,679	29,057	3.2%		56.7	3.3	3.3	2.6
Gulf Coast	2,063	34,179	46,557	5.1%		93.1	9.2	9.2	9.6

Total	88,378	375,311	905,579	100.0%	$	1,494.1	88.7	112.2	110.9


	Net proved reserves
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	PV-10 value (In thousands)

Developed—producing	45,899	233,606	509,000	$	949,472
Developed—non-producing	11,925	48,352	119,902		189,768
Undeveloped	30,554	93,353	276,677		354,823

Total proved	88,378	375,311	905,579	$	1,494,063


(Dollars in thousands, except prices)	2004		2005		2006

Future net revenue	$	1,663,141	$	3,597,300	$	3,518,020
PV-10 value		775,116		1,602,610		1,494,063
Standardized measure of discounted future net cash flows		514,041		1,067,888		1,082,209
Oil price (per Bbl)	$	43.51	$	61.04	$	61.06
Natural gas price (per Mcf)	$	6.35	$	10.08	$	5.64


	Total wells
	Gross	Net

Crude oil	5,401	1,791
Natural gas	2,286	624

Total	7,687	2,415


	Total wells		Operated Wells
	Gross	Net	Operated Wells

Mid-Continent	4,954	1,766	1,940
Permian Basin	1,487	316	312
Ark-La-Tex	128	53	53
North Texas	772	120	115
Rocky Mountains	155	41	42
Gulf Coast	191	119	127

Total	7,687	2,415	2,589


	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net

Mid-Continent	912,483	367,476	46,826	37,460
Permian Basin	87,568	50,518	19,687	17,883
Ark-La-Tex	25,687	14,190	—	—
North Texas	21,489	16,286	965	763
Rocky Mountains	41,384	13,995	19,129	9,256
Gulf Coast	78,372	45,503	15,265	9,139

Total	1,166,983	507,968	101,872	74,501


Name	Age	Position


Mark A. Fischer	58	Chairman, Chief Executive Officer and President

Joseph O. Evans	53	Chief Financial Officer and Executive Vice President and Director

Robert W. Kelly II	49	Senior Vice President and General Counsel

Larry E. Gateley	57	Senior Vice President—Reservoir Engineering and Acquisitions

James M. Miller	44	Senior Vice President—Operations and Production Engineering

Charles A. Fischer, Jr.	58	Director


Years of Service for Vesting		Percentage
1		20%
2		40%
3		60%
4		80%
5		100%


Name and Principal Position	Year	Salary ($)		Bonus(1) ($)		Stock Awards(2) ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)			Total ($)

Mark A. Fischer,	2006	$	351,258	$	245,165	—	—	—	—	$	20,688	(3)	$	617,111
Chief Executive Officer and President
Joseph O. Evans,	2006		227,285		90,369	7,514	—	—	—		13,104	(3)		338,272
Chief Financial Officer and Executive Vice President
Charles A. Fischer,	2006		207,650		89,290	—	—	—	—		19,719	(3)		316,659
Chief Administrative Officer and Executive Vice President
Larry E. Gateley,	2006		189,362		72,727	15,010	—	—	—		11,530	(3)		288,629
Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller,	2006		170,885		67,463	15,010	—	—	—		99,514	(4)		352,872
Senior Vice President— Operations and Production Engineering


	Beneficial ownership
Name(1)	Number	Percent

Mark A. Fischer(2)	372,500	42.5%
Altoma Energy G.P.(3)	224,500	25.6%
Charles A. Fischer, Jr.(4)	224,500	25.6%
Chesapeake Energy Corporation(5)	280,000	31.9%
Joseph O. Evans	—	—
Larry E. Gateley	—	—
James M. Miller	—	—
Robert W. Kelly II	—	—
All Directors and Officers as a group (6 persons)	597,000	68.1%


	December 31,			September 30,
(Dollars in thousands)	2006			2007

Current assets per GAAP	$	91,863		$	121,336
Plus—Availability under Credit Agreement		112,136			68,326
Less—Deferred tax asset on derivative instruments and asset retirement obligation		(847	)		(5,687	)
Less—Short-term derivative instruments		(7,599	)		—

Current assets as adjusted	$	195,553		$	183,975

Current liabilities per GAAP	$	104,255		$	122,970
Less—Short-term derivative instruments		(12,376	)		(17,728	)
Less—Short-term asset retirement obligation		(749	)		(749	)

Current liabilities as adjusted	$	91,130		$	104,493

Current ratio for loan compliance		2.15			1.76


Year		Percentage

2012		104.438%
2013		102.958%
2014		101.479%
2015 and thereafter		100.000%


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.


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.