As filed with the Securities and Exchange Commission on February 14, 2006

Registration No. 333-130749

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Chaparral Energy, Inc.

(Exact name of registrant as specified in charter)

Delaware	1311	73-1590941
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma 73114

(405) 478-8770

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

Robert W. Kelly II

General Counsel

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma 73114

(405) 478-8770

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

With a copy to:

David C. Buck Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 Telephone: (713) 220-4301 Facsimile: (713) 238-7126 Daniel J. Zubkoff Cahill Gordon & Reindel LLP 80 Pine Street New York, New York 10005 Telephone: (212) 701-3000 Facsimile: (212) 269-5420

Approximate date of commencement of proposed sale to the public:  As soon as practicable on or after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, 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(c) 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.  ¨

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 Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to completion, dated February 14, 2006

Prospectus

             shares

Chaparral Energy, Inc.

Common stock

Chaparral Energy, Inc. is selling                          shares of common stock, and the selling stockholders identified in this prospectus are selling an additional                          shares. We will not receive any of the proceeds from the sale of the shares by the selling stockholders. Certain of the selling stockholders are members of our management. See ”Principal and selling stockholders“ on page 84 for more information. This is the initial public offering of our common stock. The estimated initial public offering price is between $             and $            per share.

Prior to this offering, there has been no public market for our common stock. We have applied to list our common stock on the New York Stock Exchange under the symbol “CPR.”

	Per share	Total
Initial public offering price	$	$
Underwriting discount	$	$
Proceeds to Chaparral Energy, Inc., before expenses	$	$
Proceeds to selling stockholders, before expenses	$	$

We and the selling stockholders have granted the underwriters an option for a period of 30 days to purchase up to an aggregate of                          additional shares of our common stock on the same terms and conditions set forth above to cover overallotments, if any.

Investing in our common stock involves a high degree of risk. See “ Risk factors” beginning on page 17.

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.

The underwriters expect to deliver the shares of common stock to investors on                 , 2006.

JPMorgan

Banc of America Securities LLC	Lehman Brothers
Comerica Securities	Fortis Securities

                , 2006

Table of contents

	Page
Special cautionary statement regarding forward-looking statements	ii
Prospectus summary	1
Risk factors	17
Use of proceeds	32
Dividend policy	32
Capitalization	33
Dilution	34
Unaudited pro forma financial data	36
Selected consolidated historical financial data	42
Management’s discussion and analysis of financial condition and results of operations	44
Business and properties	59
Management	78
Principal and selling stockholders	84
Certain relationships and related transactions	85
Description of capital stock	87
Shares eligible for future sale	91
Material U.S. federal tax consequences for non-U.S. holders of our common stock	93
Underwriting	96
Legal matters	100
Experts	100
Reserve engineers	100
Where you can find more information	100
Glossary of terms	A-1
Index to financial statements	F-1

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock.

No action is being taken in any jurisdiction outside the United States to permit a public offering of the common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to those jurisdictions.

i

Special cautionary statement regarding forward-looking statements

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

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

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

• the amount, nature and timing of capital expenditures;

• drilling of wells;

• competition and government regulations;

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

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

• increases in proved reserves;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• estimates of proved reserves;

• exploitation or property acquisitions;

• marketing of oil and natural gas; and

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

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

A description of certain risks relating to us and our business appears under the heading “Risk factors” beginning on page 17 of this prospectus.

ii

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.

Industry and market data

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

iii

Prospectus summary

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

In this prospectus, “pro forma basis” means after giving pro forma effect to (1) our acquisition of the 99% limited partner interest in CEI Bristol Acquisition, L.P. on September 30, 2005, (2) the issuance of $325.0 million aggregate principal amount of our 8 ¹/2% Senior Notes due 2015 on December 1, 2005 and (3) the application of the net proceeds from the issuance of these notes. See “—Recent developments” and “Use of proceeds.” The number of shares and per share amounts will be adjusted to give effect to a          -for-          stock split that will be effected as a stock dividend prior to the consummation of this offering. Investors who are not familiar with oil and gas industry terms used in this prospectus should refer to the “Glossary of terms” section set forth in this prospectus.

Our business

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to development drilling. As of December 31, 2004, approximately 87% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties. On September 30, 2005, we acquired the 99% limited partner interest in CEI Bristol Acquisition, L.P., or CEI Bristol, for $158 million. We have managed this limited partnership since 2000.

As of December 31, 2004, on a pro forma basis we had estimated proved reserves of 606 Bcfe and a PV-10 value of $1,010.3 million. For the nine months ended September 30, 2005, on a pro forma basis, our average daily production was 80.9 MMcfe, a 14% increase over the comparable period in 2004. As of December 31, 2004 on a pro forma basis, our estimated reserve life would have been 22.7 years. On a pro forma basis, our revenues and Adjusted EBITDA for the year ended December 31, 2004 were $125.6 million and $82.7 million, respectively. For the nine months ended September 30, 2005, on a pro forma basis, our revenues and Adjusted EBITDA were $107.9 million and $79.0 million, respectively. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of a standardized measure of discounted future net cash flows to PV-10 value, and our definition of Adjusted EBITDA (a non-GAAP measure) and a reconciliation of our income from continuing operations before accounting change to Adjusted EBITDA, beginning on page 13.

For the period from 2001 to 2004, our proved reserves and production have grown at a compounded annual growth rate of 41% and 20%, respectively. We have grown primarily

1

through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

We have a multi-year inventory of drillable prospects and an active drilling program. We have identified over 700 proved developmental drilling locations, as well as over 2,200 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our current drilling rate. We normally have three to six drilling rigs active at any time, depending on the availability of rigs. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted one proprietary shoot and are currently permitting on two additional proprietary 3-D shoots.

Our capital expenditures for oil and gas properties for the nine months ended September 30, 2005 were $104.2 million (excluding the acquisition of the limited partner interest in CEI Bristol Acquisition, L.P.), representing a 51% increase over the comparable period in 2004. Our capital expenditure budget for oil and gas properties for 2006 is $200 million assuming this offering is consummated. We have budgeted approximately 58% of our 2006 capital expenditures on development activities (drilling—41%, enhancements—10% and tertiary recovery—7%), 37% for acquisitions and 5% for exploration activities. A majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO₂) tertiary recovery projects in the Mid-Continent and Permian Basin.

2

The following tables present proved reserves and PV-10 value as of December 31, 2004, and average daily production for the year ended December 31, 2004 and nine months ended September 30, 2005 by major areas of operation for Chaparral and CEI Bristol.

	Proved reserves as of December 31, 2004						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, 2004	Nine months ended September 30, 2005
Chaparral
Mid-Continent	31,015	193,916	380,006	73.7%	$	586.7	40.6	46.6
Permian Basin	5,532	37,656	70,848	13.7%		129.0	6.2	8.1
East Texas	1,030	20,095	26,275	5.1%		49.5	2.1	5.4
North Texas	2,810	386	17,246	3.3%		40.4	1.6	2.0
Rocky Mountains	1,241	3,206	10,652	2.1%		19.5	0.6	1.6
Gulf Coast	386	7,392	9,708	1.9%		18.2	1.0	1.5
Other	13	969	1,047	0.2%		1.8	—	—
Chaparral total	42,027	263,620	515,782	100.0%	$	845.1	52.1	65.2
CEI Bristol
Mid-Continent	913	39,165	44,643	49.6%	$	79.0	14.9	9.8
Permian Basin	974	19,948	25,792	28.6%		48.6	2.1	2.1
East Texas	102	8,567	9,179	10.2%		16.9	0.6	1.3
North Texas	357	302	2,444	2.7%		4.0	0.4	0.5
Rocky Mountains	176	1,414	2,470	2.7%		3.6	0.8	0.6
Gulf Coast	318	3,643	5,551	6.2%		13.1	1.6	1.4
CEI Bristol total	2,840	73,039	90,079	100.0%	$	165.2	20.4	15.7
Pro forma total	44,867	336,659	605,861		$	1,010.3	72.5	80.9

Business strengths

Consistent track record of low-cost reserve additions and production growth.    From 2001 to 2004, we have grown reserves and production by a compounded annual growth rate of 41% and 20%, 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 610%, 468% and 1,219% of our production in 2002, 2003 and 2004, respectively, at a fully developed average F&D cost of $1.31 per Mcfe over this three year period, which we believe is among the lowest in the industry.

Disciplined approach to acquisitions.    We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence, with reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2002, 2003 and 2004, our capital expenditures for acquisitions were $17.7 million, $19.9 million and $30.5 million, respectively. These acquisition capital expenditures represented approximately 43%, 35% and 32%, respectively, of our total

3

capital expenditures for those years. In 2005 we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added, as of September 30, 2005, an estimated 115 Bcfe of proved reserves. Not including the acquisition of CEI Bristol, we spent $37.3 million on acquisitions during the first nine months of 2005, representing approximately 36% of our total capital expenditures for that period. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

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

Inventory of drilling locations.    As of December 31, 2004, we had an inventory of over 700 proved developmental drilling locations and over 2,200 additional potential drilling locations. Not including the CEI Bristol acquisition, we spent $52.1 million on development and exploration drilling for the first nine months of 2005. We have experienced a high historical drilling success rate of approximately 90% on a weighted average basis during 2002, 2003 and 2004. For 2006, we have budgeted $92 million to drill more than 55 operated wells and to participate in more than 130 wells operated by others. Additionally, we utilize 3-D seismic data to help identify additional reserve targets in, around and under older producing fields.

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO₂ enhanced oil recovery. CO₂ enhanced oil recovery involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO₂ tertiary recovery operations, as well as specific software for modeling CO₂ enhanced recovery. We own a 29.2% interest in and operate a large CO₂ tertiary flood unit in southern Oklahoma and installed a second tertiary flood unit in the Oklahoma panhandle. We have subsequently acquired other related assets, and our proved reserves at December 31, 2004 include 14 properties, two with both proved developed producing and proved undeveloped and twelve with proved undeveloped only, that will utilize CO₂ tertiary recovery methods. These proved developed producing and proved undeveloped CO₂ tertiary recovery projects included in our proved reserves accounted for approximately 26% of our December 31, 2004 total proved reserves.

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 33 years after starting his career at Exxon as a petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 21 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Individuals in our 24-person management team have an average of over 24 years of experience each 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

4

commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:

Continue lower-risk development drilling program.    We have allocated $82 million, or 41% of our 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. We generally pursue mature properties in the second half of their life which are located in proven fields in which we have an opportunity to improve operations through cost control, and to increase production and reserves through the application of improved technology and additional drilling. Excluding the CEI Bristol acquisition, which was larger than our typical acquisition, we have spent approximately $37.3 million on acquisitions through September 30, 2005. Our 2006 acquisition capital budget is $74 million, or 37% of our total capital expenditure budget.

Apply technical expertise to enhance mature properties.    Once we acquire a property and become its 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 14 field offices throughout Oklahoma and Texas. 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, 2004, we had an inventory of 221 developed enhancement projects requiring total estimated capital expenditures of $9 million.

Expand CO₂ enhanced oil recovery activities.    We have accumulated interests in 45 fields in Oklahoma and Texas that meet the criteria for CO₂ tertiary recovery operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in a number of these fields. Four of our CO₂ projects in our proved reserves are scheduled to initiate CO₂ injection in 2006. We have a 100% ownership interest in 86 miles of CO₂ pipeline and control a 50% or larger ownership interest in an additional 160 miles of CO₂ pipeline. The planned construction of 88 miles of CO₂ pipeline will facilitate CO₂ injection in these new projects. We have budgeted $14 million in 2006 towards these projects. To support our existing CO₂ tertiary oil recovery projects, we currently inject approximately 37 MMcf per day of CO₂.

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 approximately 5% of our 2006 capital expenditures on exploratory drilling.

Control operations and costs.    We generally 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

5

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. Operations are crucial to the implementation of our programs and, accordingly, we are willing to take additional measures to become the operator. As of December 31, 2004, we operated properties comprising approximately 84% of our proved reserves.

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. Excluding PDP production attributable to the CEI Bristol acquisition, as of September 30, 2005, we had hedges in place for approximately 77%, 55% and 5% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 78%, 61% and 6% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities during each of the past three years as commodity prices have increased.

Recent developments

Issuance of 8 ¹/2% Senior Notes due 2015.    On December 1, 2005, we sold $325.0 million aggregate principal amount of 8 ¹/2% Senior Notes maturing on December 1, 2015, which we refer to as our 8 ¹/2% Senior Notes. Interest on our 8 ¹/2% Senior Notes is due semi-annually beginning June 1, 2006. The 8 ¹/2% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 ¹/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries. We used the net proceeds from the sale of our 8 ¹/2% Senior Notes to reduce outstanding indebtedness under our senior secured credit facility, and to repay indebtedness incurred in the acquisition of CEI Bristol. See “—Acquisition of CEI Bristol Acquisition, L.P.” and “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Our 8 ¹/2% Senior Notes due 2015.”

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

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

6

the acquisition to increase our production in the fourth quarter of 2005 and in 2006 by approximately 1.4 Bcfe and 4.8 Bcfe, respectively.

We funded $132 million of the acquisition costs with the proceeds from a bridge loan facility with General Electric Capital Corporation, which we refer to as the GE Bridge Loan, and the remainder with borrowings from our Credit Agreement and cash on hand. This bridge loan was repaid on December 1, 2005 with the proceeds from the issuance of our 8 ¹/2% Senior Notes. Prior to our acquisition of CEI Bristol, the borrowing base under our Credit Agreement was increased from $235.0 million to $270.0 million. Upon issuance of our 8 ¹/2% Senior Notes, our borrowing base was reduced from $270.0 million to $172.5 million.

Oklahoma Ethanol L.L.C.    In August 2005, we entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma Farmers Union Sustainable Energy LLC to construct and operate an ethanol production plant in Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of ethanol 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 $78 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $46 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 early 2007 with completion in 2008, and that our equity contribution will be approximately $20 million.

Risk factors

Our business and our business strategy are subject to a number of material risks described in “Risk factors” beginning on page 17, including:

• volatility of oil and gas prices;

• writedowns of the carrying values of our properties;

• risks inherent in estimating reserves;

• our leverage and ability to borrow future funds;

• competition for acquisitions;

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

• changes in laws and regulations; and

• losses from hedging obligations.

You should consider carefully these and other risks described in “Risk factors” before deciding to invest in shares of our common stock.

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.

7

The offering

Common stock offered:

By us:              shares

By the selling stockholders:              shares

Total offered hereby:              shares

Common stock to be outstanding immediately following the offering:              shares

The number of shares of our common stock outstanding after this offering is based on              shares of common stock outstanding as of                     , 2006.

Use of proceeds:

We intend to use the net proceeds received by us in connection with this offering to repay outstanding indebtedness under our Credit Agreement and general corporate purposes, including working capital. Certain affiliates of the underwriters to this offering are lenders under our Credit Agreement and will receive a portion of the proceeds from this offering. See “Use of proceeds” and “Underwriting.” We will not receive any of the proceeds from the sale of the shares by the selling stockholders, some of whom are members of our management. See “Principal and selling stockholders.”

Dividend policy:

We do not anticipate paying any cash dividends on our common stock.

NYSE symbol:                

CPR

Other information about this prospectus

Unless specifically stated otherwise, the information in this prospectus:

• will be adjusted to reflect a             -for-             stock split of our shares of common stock to be effected in the form of a stock dividend prior to the consummation of this offering;

• assumes no exercise of the underwriters’ over-allotment option; and

• assumes an initial public offering price of $            , which is the mid-point of the range set forth on the front cover of this prospectus.

8

Summary consolidated historical and

pro forma financial data

You should read the following summary consolidated historical and pro forma financial information in connection with the financial statements and related notes included in this prospectus, and the “Management’s discussion and analysis of financial condition and results of operations” beginning on page 44 and the “Unaudited pro forma financial data” beginning on page 36 of this prospectus. The historical consolidated financial data for each of the three fiscal years ended December 31, 2004 (except for balance sheet data as of December 31, 2002) were derived from our audited annual financial statements included in this prospectus. The data for the nine months ended September 30, 2004 and 2005 were derived from our unaudited interim consolidated 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 presentation of the results for those interim periods. Our summary historical results are not necessarily indicative of results to be expected in future periods.

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

The summary pro forma financial data for the fiscal year ended December 31, 2004 and nine months ended September 30, 2005 gives effect to the following transactions:

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

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

The unaudited pro forma condensed consolidated statements of operations data for the year ended December 31, 2004 and for the nine months ended September 30, 2005 assume the pro forma transactions described above all occurred on January 1, 2004.

The pro forma, as adjusted financial position data as of September 30, 2005 gives effect to the transactions described above and this common stock offering and the application of the net proceeds as described in “Use of proceeds.”

9

The non-generally accepted accounting principle, or non-GAAP, financial measure of Adjusted EBITDA is defined by us as income from continuing operations before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization and (4) hedge ineffectiveness, and is presented in our summary historical and pro forma financial data. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. In the supplemental sections titled “Non-GAAP financial measure and reconciliation,” we have provided the necessary explanations and reconciliations for this non-GAAP financial measure.

	Chaparral Year ended December 31,
	Historical									Pro forma 2004
(Dollars in thousands, except share and per share amounts)	2002			2003			2004
										(unaudited)
Operating results data:
Revenues
Oil and gas sales	$	42,653		$	74,186		$	113,546		$	157,856
Loss on oil and gas hedging activities		(749	)		(12,220	)		(21,350	)		(32,242	)
Total revenues		41,904			61,966			92,196			125,614
Costs and expenses
Lease operating		14,506			18,706			25,392			32,085
Production taxes and gas handling charges		3,645			5,654			9,808			15,331
Depreciation, depletion and amortization		7,910			10,376			18,234			25,547
General and administrative		4,059			4,946			5,985			7,232
Total costs and expenses		30,120			39,682			59,419			80,195
Operating income		11,784			22,284			32,777			45,419
Non-operating income (expense)
Interest expense		(3,998	)		(4,116	)		(6,162	)		(29,250	)
Other income		1,012			208			279			188
Net non-operating expense		(2,986	)		(3,908	)		(5,883	)		(29,062	)
Income from continuing operations before income taxes and accounting change		8,798			18,376			26,894			16,357
Income tax expense		3,134			6,932			9,629			5,856
Income from continuing operations before accounting change		5,664			11,444			17,265			10,501
Cumulative effect of change in accounting principle, net of income taxes		—			(887	)		—			—
Discontinued operations, net of income taxes		(617	)		—			—			—
Net income	$	5,047		$	10,557		$	17,265		$	10,501

10

	Chaparral Year ended December 31,
	Historical									Pro forma 2004
(Dollars in thousands, except share and per share amounts)	2002			2003			2004
										(unaudited)
Earnings per share (historical):
Income per share from continuing operations	$	5,664		$	11,444		$	17,265		$	10,501
Income (loss) per share from accounting change, net		—			(887	)		—			—
Income (loss) per share from discontinued operations, net		(617	)		—			—			—
Net income per share	$	5,047		$	10,557		$	17,265		$	10,501
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000			1,000			1,000			1,000
Earnings per share (pro forma for stock split):
Income per share from continuing operations	$			$			$			$
Income (loss) per share from accounting change, net
Income (loss) per share from discontinued operations, net
Net income per share	$			$			$			$
Weighted average number of shares used in calculation of basic and diluted earnings per share
Cash flow data:
Net cash provided by operating activities	$	17,480		$	32,541		$	49,849			na
Net cash used in investing activities		(27,505	)		(55,213	)		(95,120	)		na
Net cash provided by financing activities		8,921			26,146			54,061			na
Other financial data:
Capital expenditures for oil & gas properties	$	40,852		$	56,962		$	96,031			na
Adjusted EBITDA(1)		21,311			33,288			51,894		$	82,650
	As of December 31,
	2002			2003			2004
Financial position data:
Cash and cash equivalents	$	1,578		$	5,052		$	13,842
Total assets		142,919			211,086			308,126
Total debt		91,780			118,355			176,622
Undistributed earnings		20,420			30,977			48,242
Accumulated other comprehensive income (loss), net of income taxes		(3,733	)		(4,900	)		(12,107	)
Total equity		16,688			26,078			36,136

(1) Adjusted EBITDA is defined as income from continuing operations before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion, and amortization and (4) hedge ineffectiveness. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. See “Non-GAAP financial measure and reconciliation.”

11

	Chaparral Nine months ended September 30,
	Historical						Pro forma 2005
(Dollars in thousands, except share and per share amounts) (unaudited)	2004			2005
Operating results data:
Revenues
Oil and gas sales	$	76,504		$	130,727		$	160,500
Loss on oil and gas hedging activities		(14,073	)		(39,743	)		(52,579	)
Total revenues		62,431			90,984			107,921
Costs and expenses
Lease operating		18,342			25,765			30,859
Production taxes and gas handling charges		6,537			12,075			15,613
Depreciation, depletion and amortization		11,559			23,089			28,581
General and administrative		4,473			6,631			7,520
Total costs and expenses		40,911			67,560			82,573
Operating income		21,520			23,424			25,348
Non-operating income (expense)
Interest expense		(4,099	)		(8,283	)		(23,136	)
Other income		336			524			541
Net non-operating expense		(3,763	)		(7,759	)		(22,595	)
Income before income taxes		17,757			15,665			2,753
Income tax expense		6,358			5,701			1,002
Net income	$	11,399		$	9,964		$	1,751
Earnings per share (historical):
Basic and diluted income per share	$	11,399		$	9,964		$	1,751
Weighted average number of shares used in calculation of basic and diluted income per share		1,000			1,000			1,000
Earnings per share (pro forma for stock split):
Basic and diluted income per share	$			$			$
Weighted average number of shares used in calculation of basic and diluted earnings per share
Cash flow data:
Net cash provided by operating activities	$	36,285		$	50,840			na
Net cash used in investing activities		(68,344	)		(222,009	)		na
Net cash provided by financing activities		38,256			208,384			na
Other financial data:
Capital expenditures for oil & gas properties	$	69,023		$	260,985			na
Adjusted EBITDA(1)		35,011			58,717		$	78,986
				As of September 30, 2005
				Historical			Proforma, as adjusted(2)
Financial position data:
Cash and cash equivalents(3)				$	51,057		$	83,557
Total assets					632,554			674,054
Total debt					388,229			337,729
Undistributed earnings					55,147			na
Accumulated other comprehensive income (loss), net of income taxes					(75,030	)		na
Total equity (deficit)					(19,882	)		na

(1) Adjusted EBITDA is defined as income from continuing operations before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion, and amortization and (4) hedge ineffectiveness. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as part of the CEI Bristol acquisition. See “Non-GAAP financial measure and reconciliation.”

(2) A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) cash and cash equivalents and total assets by $        , assuming the number of shares offered by us set forth by on the cover page of this prospectus remains the same and after deducting underwriting discounts and estimated offering expenses payable by us.

(3) Includes $42.1 million of cash subsequently used to settle hedges of CEI Bristol on October 3, 2005.

12

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, 2004 less 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, 2004 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	$	586.7	$	200.4	$	386.3
Permian Basin		129.0		44.1		84.9
East Texas		49.5		16.9		32.6
North Texas		40.4		13.8		26.6
Rocky Mountains		19.5		6.7		12.8
Gulf Coast		18.2		6.2		12.0
Other		1.8		0.5		1.3
Total PV-10	$	845.1	$	288.6	$	556.5

13

Adjusted EBITDA

We define Adjusted EBITDA as income from continuing operations before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization and (4) hedge ineffectiveness.

Our Adjusted EBITDA measure provides additional information which may be used to better understand our operations. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under generally accepted accounting principles and, accordingly, it may not be a comparable measurement to those used by other companies. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. The following table provides a reconciliation of income from continuing operations before accounting changes to Adjusted EBITDA:

	Historical										Pro forma
	Year ended December 31,						Nine months ended September 30,				Year ended December 31,		Nine months ended September 30,
(Dollars in thousands) (unaudited)	2002		2003		2004		2004		2005		2004		2005
Income from continuing operations before accounting change	$	5,664	$	11,444	$	17,265	$	11,399	$	9,964	$	10,501	$	1,751
Interest expense		3,998		4,116		6,162		4,099		8,283		29,250		23,136
Income tax expense		3,134		6,932		9,629		6,358		5,701		5,856		1,002
Depreciation, depletion and amortization		7,910		10,376		18,234		11,559		23,089		25,547		28,581
Unrealized loss on ineffective portion of hedges		605		420		604		1,596		11,680		604		11,680
Loss on CEI Bristol hedges		—		—		—		—		—		10,892		12,836
Adjusted EBITDA	$	21,311	$	33,288	$	51,894	$	35,011	$	58,717	$	82,650	$	78,986

14

Summary historical and pro forma reserve information

The following table summarizes our historical and pro forma 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, 2002, 2003 and 2004), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2002 and 2003 were prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Estimates of our net proved oil and natural gas reserves as of December 31, 2004 were prepared by Cawley, Gillespie and Associates, Inc. (62% of PV-10 value) and Lee Keeling & Associates, Inc. (13% of PV-10 value), both independent petroleum engineering firms, and our engineering staff (25% of PV-10 value). Estimates of the net proved oil and natural gas reserves of CEI Bristol as of December 31, 2004 were also prepared by Cawley, Gillespie and Associates, Inc.

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,						Pro forma as of December 31, 2004
	2002		2003		2004
Proved reserves
Oil (Mbbl)		16,243		16,777		42,027		44,867
Natural gas (MMcf)		151,773		203,677		263,620		336,659
Natural gas equivalent (MMcfe)		249,231		304,339		515,782		605,861
Proved developed reserves percentage		78%		81%		56%		60%
PV-10 value (in thousands)	$	320,648	$	488,305	$	845,064	$	1,010,134
Estimated reserve life (in years)(1)		19.6		19.9		27.2		22.7
Cost incurred (in thousands):
Property acquisition costs	$	17,730	$	19,864	$	30,546	$	30,932
Development costs		21,343		36,758		62,371		72,299
Exploration costs		1,779		340		3,114		3,299
Total	$	40,852	$	56,962	$	96,031	$	106,530
Annual reserve replacement ratio(2)		610%		468%		1,219%		907%
Three-year fully developed average F&D cost ($/Mcfe)					$	1.31

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

(2) 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.

15

Summary historical production and sales data

The following table sets forth certain information regarding Chaparral’s historical 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,
	2002		2003		2004		2004		2005
Net production volumes
Oil (MBbls)		791		924		1,173		852		1,026
Natural gas (MMcf)		7,952		9,762		11,923		8,241		11,456
Combined (MMcfe)		12,698		15,306		18,961		13,353		17,612
Oil and gas sales ($ in thousands)(1)
Oil	$	19,560	$	27,643	$	47,537	$	32,611	$	54,921
Natural gas		23,093		46,543		66,009		43,893		75,806
Total	$	42,653	$	74,186	$	113,546	$	76,504	$	130,727
Oil average sales price (per Bbl)
Price excluding hedges	$	24.73	$	29.92	$	40.53	$	38.28	$	53.53
Price including hedges	$	25.00	$	26.70	$	29.16	$	30.98	$	35.67
Natural gas average sales price (per Mcf)
Price excluding hedges	$	2.90	$	4.77	$	5.54	$	5.33	$	6.62
Price including hedges	$	2.78	$	3.82	$	4.86	$	4.37	$	4.75
Average production cost and production taxes (per Mcfe)
Average production cost(2)	$	1.14	$	1.22	$	1.34	$	1.37	$	1.46
Average production taxes(3)	$	0.29	$	0.37	$	0.52	$	0.49	$	0.69

(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), and the administrative costs of field offices and insurance.

(3) Includes property and severance taxes and gas handling charges.

16

Risk factors

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. In such a case, you may lose all or part of your investment. 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.

Risks relating to our business

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

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

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

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

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

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

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

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• financial and commercial market uncertainty;

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

• worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our 8 ¹/2% Senior Notes, or make planned capital expenditures.

17

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, 2004 PV-10 value uses realized prices based on a Henry Hub spot price of $6.35 per MMBtu for natural gas and a WTI Cushing spot price of $43.51 per Bbl for oil.

Approximately 44% of our total proved reserves as of December 31, 2004 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2004, approximately 44% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and

18

successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

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

As of September 30, 2005 on a pro forma, as adjusted basis after giving effect to the issuance of our 8 ¹/2% Senior Notes, this offering and the use of proceeds from the issuance of these notes and this offering, our long-term indebtedness including capital leases would have been approximately $337.7 million, with no amount drawn under the revolving credit line of our Credit Agreement. On a pro forma, as adjusted basis after giving effect to the issuance of our 8 ¹/2% Senior Notes, this offering and the use of proceeds from the issuance of these notes and this offering, our total debt would have been $337.7 million and our total book capitalization would have been $456.8 million at September 30, 2005. We increased the maximum commitment amount and the borrowing base under our Credit Agreement to $450.0 million and $235.0 million, respectively, on June 22, 2005 and further increased the borrowing base to $270.0 million on September 30, 2005 prior to our acquisition of CEI Bristol. Our borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of the issuance of our 8 ¹/2% Senior Notes. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

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

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

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

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

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

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

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

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

19

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

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

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

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

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

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

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

Significant capital expenditures are required to replace our reserves.

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

20

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 44% of our total estimated proved reserves (by volume) at December 31, 2004 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and enhanced recovery operations. Our reserve estimates reflect that our production rate on currently producing properties will decline at annual rates of approximately 19.6%, 13.1% and 10.6% during 2006, 2007 and 2008, respectively. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

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

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

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

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

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing

21

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:

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• unitization and pooling of properties;

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

• well stimulation processes;

• produced water disposal;

• safety precautions;

• operational reporting; and

• taxation.

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

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

22

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

• other environmental damages.

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

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

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the New York Mercantile Exchange, or NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. Under our current hedging policy, we may hedge up to 80% of our anticipated monthly production for a maximum three-year period. As of September 30, 2005, we had hedged 20,130 MMcf and 2,013 MBbl of our natural gas and oil production for 2005 through 2008 at average monthly prices ranging from $6.06 to $10.02 per Mcf of natural gas and $36.00 to $64.53 per Bbl of oil. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2005 was a liability of approximately $177.3 million, which includes approximately $42.1 million of hedge settlement costs related to the CEI Bristol acquisition. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

• our production is less than expected;

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

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

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

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

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

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

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves,

23

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.

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.

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

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

• injury or loss of life;

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

• pollution or other environmental damage;

• clean-up responsibilities;

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

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

24

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

Costs of environmental liabilities could exceed our estimates.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

• the uncertainties in estimating clean up costs;

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

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

• future changes to environmental laws and regulations.

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

We are subject to financing and interest rate exposure risks.

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

• our credit ratings;

• interest rates;

• the structured and commercial financial markets;

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

• tax rates due to new tax laws.

All of the outstanding borrowings under the Credit Agreement as of September 30, 2005 are subject to market rates of interest as determined from time to time by the banks. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

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

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest

25

owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables, but future concentration of sales of oil and natural gas commensurate with decreases in commodity prices could result in adverse effects.

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

Risks relating to this offering and to owning our common stock

Certain stockholders’ shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.

After this offering, we will have outstanding              shares of common stock. Of these shares, the             shares we and the selling stockholders are selling in this offering, or              shares if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. All of the shares outstanding other than the shares sold in this offering (a total of              shares, or              shares if the underwriters exercise their over-allotment option in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and subject to lock-up arrangements.

In connection with this offering, we and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements,              shares, or              shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144.

After this offering, the holders of              shares, or              shares if the underwriters exercise their over-allotment option in full, will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.

26

Purchasers of common stock will experience immediate and substantial dilution.

Based on an assumed initial public offering price of $          per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $          per share in the net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of September 30, 2005 after giving effect to this offering would be $          per share. Please read “Dilution” for a complete description of the calculation of net tangible book value.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could discourage or make it more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

• a classified board of directors, so that only approximately one-third of our directors are elected each year;

• limitations on the removal of directors;

• the prohibition of stockholder action by written consent; and

• limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

Because our existing dividend policy and contractual restrictions limit our ability to pay dividends, investors must look solely to stock appreciation for a return on their investment in us.

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our Credit Agreement and the indenture governing our 8 ¹/2% Senior Notes limit the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

27

If our stock price declines after the initial offering, you could lose a significant part of your investment.

The market price of our common stock could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

• the failure of securities analysts to cover our common stock after this offering or changes in securities analysts’ recommendations and their estimates of our financial performance;

• the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;

• fluctuations in broader stock market prices and volumes, particularly among securities of oil and gas exploration and production companies;

• changes in market valuations of similar companies;

• additions or departures of key personnel;

• commencement of or involvement in litigation;

• announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;

• variations in our quarterly results of operations or cash flows or those of other oil and gas exploration and production companies;

• risks relating to our business and our industry, including those discussed above;

• strategic actions by us or our competitors;

• future issuances and sales of our common stock, including sales by our management;

• changes in general conditions in the U.S. economy, financial markets or the oil and gas industry; and

• investor perceptions of the investment opportunity associated with our common stock relative to other investment alternatives.

In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. These market fluctuations may also result in a lower price of our common stock.

There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity. Our stock price will fluctuate after this offering, as a result, you could lose a significant part or all of your investment.

Prior to this offering, there has not been a public market for our common stock. We have applied to list our common stock on the NYSE. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the NYSE or otherwise or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the shares will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently,

28

you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and requirements of the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of the time of our board of directors and management and will increase our costs and expenses. We will need to:

• institute a more comprehensive compliance function;

• design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

• prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

• establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

• involve and retain to a greater degree outside counsel and accountants in the above activities; and

• establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will require us to modify our director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

Failure by us to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could have a material adverse effect on our business and stock price.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 as of December 31, 2007. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules

29

and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the NYSE. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence in our financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may be adversely affected.

Our controlling stockholders may have conflicts of interest with other stockholders in the future.

After this offering, Mark A. Fischer, our President and Chief Executive Officer, and Charles A. Fischer, Jr., our Executive Vice President and Chief Administrative Officer, will beneficially own approximately     % of our common stock, or approximately     % if the underwriters exercise their over-allotment option in full. As a result, Mark A. Fischer and Charles A. Fischer, Jr. will be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as this group continues to own a significant amount of the outstanding shares of our common stock, they will continue to be able to strongly influence or effectively control our decisions, including whether to pursue or consummate potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of Mark A. Fischer and Charles A. Fischer, Jr. may not coincide with the interests of other holders of our common stock.

We are a “controlled company” within the meaning of the New York Stock Exchange rules and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements.

Because our existing three stockholders acting as a group will beneficially own in excess of 50% of our outstanding shares of common stock after the completion of this offering, these stockholders acting together will be able to control the composition of our board of directors and to direct our management and policies. We will be deemed to be a “controlled company” under the rules of the NYSE. Under these rules, we may elect not to comply with certain corporate governance requirements of the NYSE, including:

• the requirement that a majority of our board of directors consist of independent directors;

• the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

• the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

30

Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. These stockholders’ significant ownership interest could adversely affect investors’ perceptions of our corporate governance.

Affiliates of several of the underwriters of this offering are lenders and/or agents under our Credit Agreement, which may present conflicts of interest.

JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. The amount of outstanding indebtedness owed to these lender affiliates under our Credit Agreement will be reduced with a portion of the net proceeds from this offering, which may result in these underwriters being deemed to have received more than 10% of the net offering proceeds. Accordingly, this offering will be made in accordance with the applicable provisions of Rule 2720 of the Conduct Rules of the National Association of Securities Dealers, Inc., which requires, among other things, that the initial public offering price be no higher than that recommended by a “qualified independent underwriter.” Lehman Brothers Inc. is serving as the qualified independent underwriter in connection with this offering. See “Use of proceeds” and “Underwriting.”

31

Use of proceeds

We estimate that our net proceeds from this offering will be approximately $139.0 million, assuming an initial public offering price of $             per share and after deducting underwriting discounts and commissions and estimated offering expenses. A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) the net proceeds to us from this offering by $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and estimated offering expenses payable by us. We will not receive any of the net proceeds from the sale of shares of common stock by the selling stockholders, some of whom are members of our management. See “Principal and selling stockholders.” We intend to use $             million of the net proceeds from this offering to repay the outstanding indebtedness on our Credit Agreement and will use the remaining $             for working capital and general corporate purposes. Although we do not have any material pending or probable acquisitions, we anticipate that we may draw down additional amounts in the future for acquisitions.

As of September 30, 2005, we had $243.5 million outstanding under our Credit Agreement. Interest rates on approximately $208.5 million and $9.0 million were based on LIBOR (effective rates of 5.88% and 5.81%, respectively, at September 30, 2005). In addition at September 30, 2005 we had $26.0 million outstanding bearing interest at prime plus a margin (effective rate of 7.25%). Effective October 5, 2005 this amount was converted to a LIBOR loan with interest at 5.94%. We used the borrowings under the revolving credit line to acquire oil and gas properties and to fund our capital budget for drilling and enhancements. On December 1, 2005 we issued $325 million aggregate principal amount of our 8 ¹/2% Senior Notes and used a portion of the proceeds from the offering of these notes to repay approximately $184.0 million of the outstanding indebtedness under our Credit Agreement. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of the issuance of our 8 ¹/2% Senior Notes. As of January 31, 2006, we had $119.0 million outstanding under our Credit Agreement.

Certain affiliates of the underwriters to this offering are lenders under our Credit Agreement. JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. We intend to repay $             million of the amounts outstanding under our Credit Agreement with a portion of the net proceeds of this offering, of which approximately $             million will reduce the indebtedness outstanding to such affiliates in the aggregate. See “Underwriting.”

Dividend policy

Following this offering of our common stock, we do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain all future earnings following this offering to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently limited in our ability to pay dividends under our Credit Agreement and the indenture governing our 8 ¹/2% Senior Notes.

32

Capitalization

The following table sets forth our capitalization as of September 30, 2005:

• on a historical basis;

• on a pro forma basis to reflect the issuance of $325.0 million principal amount of our 8 ¹/2% Senior Notes and the repayment of the GE Bridge Loan with the net proceeds from the issuance of these notes; and

• on a pro forma, as adjusted basis to reflect a          -for-          stock split to be effected as a stock dividend prior to the consummation of this offering, this offering and the application of the net proceeds from this offering as described under “Use of proceeds” above, as if this offering occurred on September 30, 2005.

As of December 1, 2005, we had $94.0 million of indebtedness outstanding under our Credit Agreement, a portion of which will be repaid with the net proceeds of this offering as described under “Use of proceeds.” This table is unaudited and should be read together with our financial statements and the accompanying notes included in this prospectus.

				As of September 30, 2005
(Dollars in thousands)	Historical			Pro forma			Pro forma, as adjusted(1)
Cash and cash equivalents(2)	$	51,057		$	51,057		$	130,557
GE Bridge Loan		132,000			—			—
Long-term debt, including capital leases and current maturities(3):
Credit Agreement		243,500			59,500			—
Other		12,729			12,729			12,729
8 1/2% Senior Notes due 2015		—			325,000			325,000
Total debt		388,229			397,229			337,729
Stockholders’ equity (deficit):
Common stock, $.01 par value; 1,000 shares issued and outstanding actual and pro forma;          shares issued and outstanding pro forma, as adjusted		1			1			1
Additional paid-in capital		0			0			139,000
Retained earnings		55,147			55,147			55,147
Accumulated other comprehensive loss, net of taxes		(75,030	)		(75,030	)		(75,030	)
Total stockholders’ equity (deficit)		(19,882	)		(19,882	)		119,118
Total capitalization	$	368,347		$	377,347		$	456,847

(1) A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) each of as adjusted cash and cash equivalents, additional paid-in capital, total stockholders’ equity and total capitalization by $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and estimated offering expenses payable by us. The pro forma information discussed above is illustrative only and following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

(2) Includes $42.1 million of cash subsequently used to settle hedges of CEI Bristol and $0.35 million used to pay a cash distribution on October 3, 2005.

(3) Includes current maturities of long-term debt and capital leases of $2.9 million.

33

Dilution

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock that will be outstanding after giving effect to a              stock split to be effected in the form of a stock dividend prior to the closing of this offering. At September 30, 2005, we had a net tangible book deficit of $(19.9) million, or $             per share of outstanding common stock after giving effect to a              -for-             stock split to be effected in the form of a stock dividend prior to the closing of this offering. After giving effect to the sale of              shares of common stock in this offering at an assumed initial public offering price of $         per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at September 30, 2005 would have been $119.1 million or $         per share. This represents an immediate increase in such net tangible book value of $         per share to existing stockholders and an immediate and substantial dilution of $         per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:

Assumed initial public offering price per share		$
Net tangible book value per share as of September 30, 2005	$
Increase attributable to new public investors	$
As adjusted net tangible book value per share after this offering		$
Dilution in as adjusted net tangible book value per share to new investors		$

A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) our pro forma net tangible book value by $         million, our net tangible book value per share by $         per share and the dilution in pro forma net tangible book value to new investors in this offering by $         per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

The following table summarizes, on an as adjusted basis set forth above as of September 30, 2005, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $            , the mid-point of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.

	Shares Purchased(1)		Total Consideration(2)			Average Price Per Share
	Number	Percent	Amount		Percent
Existing Stockholders		%	$	1,000	%	$
New Public Investors
Total		100.0%	$		100.0%

(1) The number of shares disclosed for the existing stockholders includes              shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholders in this offering.

(2) A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) total consideration paid by new investors by $             million, or increase (decrease) the percent of total consideration paid by new investors by         %, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

34

As of September 30, 2005, there were              shares of our common stock outstanding, after giving effect to the stock split to be effected in the form of a stock dividend prior to the closing of this offering, held by three stockholders of record. Sales by the selling stockholders in this offering will reduce the number of shares of common stock held by existing stockholders to              or approximately         % of the total number of shares of common stock outstanding after this offering and will increase the number of shares of common stock held by new investors to             or approximately         % of the total number of shares of common stock outstanding after this offering.

35

Unaudited pro forma financial data

The following unaudited pro forma condensed financial information for the fiscal year ended December 31, 2004 and nine months ended September 30, 2005 gives effect to the following transactions:

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

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

The following unaudited pro forma financial information and explanatory notes present how the combined financial statements of Chaparral and CEI Bristol may have appeared had the businesses actually been combined as of January 1, 2004.

The unaudited pro forma combined financial information shows the impact of the acquisition of the limited partners’ interest in CEI Bristol on Chaparral’s historical results of operations under the purchase method of accounting. The unaudited pro forma financial information combines the historical financial information of Chaparral and CEI Bristol for the nine months ended September 30, 2005 and for the year ended December 31, 2004.

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

36

Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement of

operations for the nine months ended September 30, 2005

(Dollars in thousands, except share and per share amounts)	Chaparral historical			CEI Bristol historical			Adjustments (Note 2)			Pro forma
Revenues
Oil and gas sales	$	130,727		$	29,773			—		$	160,500
Loss on oil and gas hedging activities		(39,743	)		(12,836	)		—			(52,579	)
Total revenues		90,984			16,937						107,921
Costs and expenses
Lease operating		25,765			5,787		$	(693	)(a)		30,859
Production tax and gas handling charges		12,075			3,538			—			15,613
Depreciation, depletion and amortization		23,089			4,818			674	(b)		28,581
General and administrative		6,631			196			693	(a)		7,520
Total costs and expenses		67,560			14,339			674			82,573
Operating income		23,424			2,598			(674	)		25,348
Non-operating income (expense)
Interest expense		(8,283	)		—			(14,853	)(d)		(23,136	)
Other income		524			20			(3	)(e)		541
Net non-operating income (expense)		(7,759	)		20			(14,856	)		(22,595	)
Income from continuing operations before income taxes		15,665			2,618			(15,530	)		2,753
Income tax expense		5,701			—			(4,699	)(f)		1,002
Net income	$	9,964		$	2,618		$	(10,831	)	$	1,751
Earnings per share (historical)
Net income per share	$	9,964								$	1,751
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000									1,000
Earnings per share (pro forma for stock split)
Net income per share	$									$
Weighted average number of shares used in calculation of basic and diluted earnings per share

37

Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement

of operations for the year ended December 31, 2004

(Dollars in thousands, except share and per share amounts)	Chaparral historical			CEI Bristol historical			Adjustments (Note 2)			Pro forma
Revenues
Oil and gas sales	$	113,546		$	44,310			—		$	157,856
Loss on oil and gas hedging activities		(21,350	)		(10,892	)		—			(32,242	)
Total revenues		92,196			33,418			—			125,614
Costs and expenses
Lease operating		25,392			7,589		$	(896	)(a)		32,085
Production tax and gas handling charges		9,808			5,523			—			15,331
Depreciation, depletion and amortization		18,234			8,571			(1,258	)(b)		25,547
Impairment of long-lived assets		—			2,180			(2,180	)(c)		—
General and administrative		5,985			351			896	(a)		7,232
Total costs and expenses		59,419			24,214			(3,438	)		80,195
Operating income		32,777			9,204			3,438			45,419
Non-operating income (expense)
Interest expense		(6,162	)		—			(23,088	)(d)		(29,250	)
Other income		279			123			(214	)(e)		188
Net non-operating income (expense)		(5,883	)		123			(23,302	)		(29,062	)
Income from continuing operations before income taxes		26,894			9,327			(19,864	)		16,357
Income tax expense		9,629			—			(3,773	)(f)		5,856
Net income	$	17,265		$	9,327		$	(16,091	)	$	10,501
Earnings per share (historical)
Net income per share	$	17,265								$	10,501
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000									1,000
Earnings per share (pro forma for stock split)
Net income per share	$									$
Weighted average number of shares used in calculation of basic and diluted earnings per share

38

Notes to unaudited pro forma condensed

consolidated statements of operations

Note 1: Basis of presentation

The accompanying unaudited pro forma statements of operations of Chaparral for the nine months ended September 30, 2005 and the year ended December 31, 2004 have been prepared to give effect to the issuance of $325.0 million principal amount of the notes issued on December 1, 2005, and the acquisition of CEI Bristol as if the transactions occurred on January 1, 2004.

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

All intercompany balances and transactions have been eliminated.

Note 2: Pro forma adjustments

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

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

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

(c) Represents the elimination of impairment of oil and gas properties due to change in accounting for impairment for CEI Bristol from successful efforts to a full cost ceiling test.

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

(Dollars in thousands)	Year ended December 31, 2004			Nine months ended September 30, 2005
Historical interest expense	$	6,162		$	8,283
Interest expense resulting from the notes issued		27,625			20,719
Reduction in interest expense from the reduction of the revolving credit line		(5,437	)		(6,541	)
Amortization of $9.0 million deferred financing costs related to the notes issued—10 years		900			675
Total pro forma interest expense	$	29,250		$	23,136

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

(f) Adjustments to record the income tax impact of the inclusion of CEI Bristol’s results of operations and the pro forma adjustments at Chaparral’s effective tax rate of 35.8% in 2004 and 36.4% in 2005.

39

Note 3: Unaudited supplemental pro forma combined information related to oil and gas activities

The following unaudited supplemental pro forma combined information for oil and gas producing activities is presented pursuant to the disclosure requirements of Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.”

Pro forma combined reserve quantity information

The following table sets forth the changes in net reserve quantities of oil and gas reserves for Chaparral, CEI Bristol and on a pro forma combined basis for the year ended December 31, 2004.

	Chaparral historical						CEI Bristol historical						Pro forma
	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)		Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)		Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at December 31, 2003	16,777		203,677		304,339		2,708		68,835		85,083		19,485		272,512		389,422
Purchase of minerals in place	3,724		39,894		62,238		143		6,334		7,192		3,867		46,228		69,430
Sales of minerals in place	(91	)	(201	)	(747	)	—		—		—		(91	)	(201	)	(747	)
Extensions and discoveries	1,589		24,470		34,004		19		4,014		4,128		1,608		28,484		38,132
Revisions	2,051		2,229		14,535		186		(471	)	645		2,237		1,758		15,180
Improved recoveries	19,150		5,474		120,374		58		642		990		19,208		6,116		121,364
Production	(1,173	)	(11,923	)	(18,961	)	(275	)	(6,315	)	(7,965	)	(1,448	)	(18,238	)	(26,926	)
Balance at December 31, 2004	42,027		263,620		515,782		2,839		73,039		90,073		44,866		336,659		605,855
Proved developed reserves:
December 31, 2004	17,358		186,544		290,692		2,568		58,918		74,326		19,926		245,462		365,018

Pro forma combined standardized measure of discounted future net cash flows

The following table sets forth the standardized measure of discounted future net cash flows relating to proved oil and gas reserves of Chaparral, CEI Bristol and on a pro forma combined basis as of December 31, 2004, as well as changes therein for the year then ended for Chaparral, CEI Bristol and on a pro forma combined basis (including adjustments to recognize the future tax effects on CEI Bristol):

(Dollars in thousands)	Chaparral historical			CEI Bristol historical			Adjustments			Pro forma
Future cash flows	$	3,324,252		$	530,846					$	3,855,098
Future production costs		(1,095,352	)		(178,721	)					(1,274,073	)
Future development and abandonment costs		(325,115	)		(17,797	)					(342,912	)
Future income tax provision		(657,950	)		—		$	(110,604	)		(768,554	)
Net future cash flows		1,245,835			334,328			(110,604	)		1,469,559
Less effect of 10% discount factor		(689,309	)		(169,125	)		55,951			(802,483	)
Standardized measure of discounted future net cash flows	$	556,526		$	165,203		$	(54,653	)	$	667,076

40

Pro forma sources of changes in standardized measure of discounted future net cash flows

The principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the proved oil and gas reserves of Chaparral, CEI Bristol and pro forma combined for the year ended December 31, 2004 are as follows:

(Dollars in thousands)	Chaparral historical			CEI Bristol historical			Adjustments			Pro forma
Beginning of year	$	325,250		$	140,440		$	(43,760	)	$	421,930
Sale of oil and gas produced, net of production costs		(78,472	)		(31,198	)					(109,670	)
Net changes in prices and production costs		89,687			9,986						99,673
Extensions and discoveries		56,933			2,471						59,404
Improved recoveries		143,366			5,696						149,062
Changes in future development costs		(69,721	)		(6,846	)					(76,567	)
Development costs incurred during the period that reduced future development costs		11,230			2,491						13,721
Revisions of previous quantity estimates		32,775			1,121						33,896
Purchases and sales of reserves in place, net		109,754			17,468						127,222
Accretion of discount		49,565			14,044						63,609
Net changes in income taxes		(126,942	)		—			(10,893	)		(137,835	)
Changes in production rates and other		13,101			9,530						22,631
End of year	$	556,526		$	165,203		$	(54,653	)	$	667,076

41

Selected consolidated historical financial data

You should read the following historical 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, 2004 were derived from our audited consolidated financial statements. The data for the nine months ended September 30, 2004 and 2005 were derived from our unaudited interim consolidated 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.

	Year ended December 31,															Nine months ended September 30,
(Dollars in thousands)	2000			2001			2002			2003			2004			2004			2005
																(unaudited)
Operating results data:
Revenues
Oil and gas sales	$	37,796		$	44,250		$	42,653		$	74,186		$	113,546		$	76,504		$	130,727
Gain (loss) on oil and gas hedging activities		(6,879	)		10			(749	)		(12,220	)		(21,350	)		(14,073	)		(39,743	)
Total revenues		30,917			44,260			41,904			61,966			92,196			62,431			90,984
Costs and expenses
Lease operating		8,401			13,025			14,506			18,706			25,392			18,342			25,765
Production taxes and gas handling charges		3,132			3,767			3,645			5,654			9,808			6,537			12,075
Depreciation, depletion and amortization		3,162			5,835			7,910			10,376			18,234			11,559			23,089
General and administrative		2,294			3,506			4,059			4,946			5,985			4,473			6,631
Total costs and expenses		16,989			26,133			30,120			39,682			59,419			40,911			67,560
Operating income		13,928			18,127			11,784			22,284			32,777			21,520			23,424
Non-operating income (expense)
Interest expense		(4,243	)		(4,966	)		(3,998	)		(4,116	)		(6,162	)		(4,099	)		(8,283	)
Other income		318			201			1,012			208			279			336			524
Net non-operating expense		(3,925	)		(4,765	)		(2,986	)		(3,908	)		(5,883	)		(3,763	)		(7,759	)
Income from continuing operations before income taxes and accounting change		10,003			13,362			8,798			18,376			26,894			17,757			15,665
Income tax expense		3,764			5,099			3,134			6,932			9,629			6,358			5,701
Income from continuing operations before accounting change		6,239			8,263			5,664			11,444			17,265			11,399			9,964
Cumulative effect of change in accounting principle, net of income taxes		—			—			—			(887	)		—			—			—
Discontinued operations, net of income taxes		—			(575	)		(617	)		—			—			—			—
Net income	$	6,239		$	7,688		$	5,047		$	10,557		$	17,265		$	11,399		$	9,964

42

	Year ended December 31,															Nine months ended September 30,
(Dollars in thousands, except share and per share amounts)	2000			2001			2002			2003			2004			2004			2005
																(unaudited)
Earnings per share (historical):
Income per share from continuing operations	$	6,239		$	8,263		$	5,664		$	11,444		$	17,265		$	11,399		$	9,964
Income (loss) per share from accounting change, net		—			—			—			(887	)		—			—			—
Income (loss) per share from discontinued operations, net		—			(575	)		(617	)		—			—			—			—
Net income per share	$	6,239		$	7,688		$	5,047		$	10,557		$	17,265		$	11,399		$	9,964
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000			1,000			1,000			1,000			1,000			1,000			1,000
Earnings per share (pro forma for stock split):
Income per share from continuing operations	$			$			$			$			$			$			$
Income (loss) per share from accounting change, net
Income (loss) per share from discontinued operations, net
Net income per share	$			$			$			$			$			$			$
Weighted average number of shares used in calculation of basic and diluted earnings per share
Cash flow data:
Net cash provided by operating activities	$	19,062		$	13,036		$	17,480		$	32,541		$	49,849		$	36,285		$	50,840
Net cash used in investing activities		(21,565	)		(47,846	)		(27,505	)		(55,213	)		(95,120	)		(68,344	)		(222,009	)
Net cash provided by financing activities		11,378			24,821			8,921			26,146			54,061			38,256			208,384

	As of December 31,													As of September 30,
(Dollars in thousands)	2000		2001		2002			2003			2004			2005
														(unaudited)
Financial position data:
Cash and cash equivalents	$	10,647	$	2,237	$	1,578		$	5,052		$	13,842		$	51,057
Total assets		84,839		129,855		142,919			211,086			308,126			632,554
Total debt		54,438		79,868		91,780			118,355			176,622			388,229
Undistributed earnings		7,686		15,373		20,420			30,977			48,242			55,147
Accumulated other comprehensive income (loss), net of income taxes		—		3,379		(3,733	)		(4,900	)		(12,107	)		(75,030	)
Total equity (deficit)		7,687		18,753		16,688			26,078			36,136			(19,882	)

43

Management’s discussion and analysis of financial

condition and results of operations

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

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

Overview

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, East Texas, North Texas and the Rocky Mountains. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and enhanced oil recovery projects. As of December 31, 2004, we had estimated proved reserves of 516 Bcfe, with a PV-10 value of $845 million. Our reserves were 56% proved developed and 51% gas.

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

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• quantity of oil and natural gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

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

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on currently producing properties will decline at annual rates of approximately 19.6%, 13.1% and 10.6% during 2006, 2007 and 2008, 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.

44

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

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

• the quantity of our proved oil and gas reserves;

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

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

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

Comparison of nine months ended September 30, 2005 to nine months ended September 30, 2004

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $54.2 million, or 71%, from 2004. The increase was due to average realized prices being 30% higher in 2005 and an increase of 32% in production volumes. The average prices received for oil increased 40% to $53.53 per barrel and for gas increased 25% to $6.62 per Mcf compared to 2004. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $25.7 million from 2004. The effect of our hedging program decreased average realized prices $2.26 per Mcfe in 2005 compared to a decrease of $1.05 of Mcfe in 2004.

Production volumes increased 32% (4,259 MMcfe) from 2004 primarily due to our expanded drilling program, the addition of volumes from acquisitions and enhancements of our existing properties. Production volumes increased by 18% (1,877 MMcfe) in the Mid-Continent, 43% (651 MMcfe) in the Permian Basin, 191% (954 MMcfe) in East Texas, 94% (215 MMcfe) in the Gulf Coast, 174% (336 MMcfe) in North Texas, and 115% (226 MMcfe) in the Rocky Mountains.

Lease operating expenses.    Lease operating expenses increased $7.4 million, or 40%, from 2004 due to increases in the number of producing wells and higher oilfield service costs. We incurred $3.2 million of costs associated with workovers in 2005 compared to $1.7 million in 2004. On a per unit basis, lease operating expenses increased $0.09 per Mcfe primarily due to higher field level costs.

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $5.5 million from 2004. Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased by $3.7 million from 2004. This increase was caused by a 30% increase in prices and a 32% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.41 to $0.53 due primarily to higher prices. Gas handling charges increased by $1.8 million primarily caused by increased production.

Depreciation, depletion and amortization (DD&A).    DD&A increased $11.5 million, or 100%, primarily due to an increase in DD&A on oil and gas properties of $10.7 million. For oil and gas properties, $4.9 million of the increase was due to higher production volumes in 2005 and $5.8 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.45 to $1.31 per Mcfe primarily due to addition of higher-cost CO₂ tertiary recovery reserves to our proved undeveloped reserves at the end of 2004.

45

General and administrative expenses (G&A).    G&A expense increased by $2.2 million, or 48%, from 2004. Approximately $0.4 million of the increase is due to professional fees associated with documenting our internal controls over financial reporting for compliance with the Sarbanes-Oxley Act of 2002. The remainder of the increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $4.3 million in 2005 and $3.0 million in 2004 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.33 per Mcfe in 2004 to $0.38 per Mcfe in 2005.

Interest expense.    Interest expense increased $4.2 million, or 102%, from 2004 primarily due to an increase of approximately $79 million in the average amount of outstanding debt in 2005 (which is 58% higher than in 2004) and an increase in the average interest rate paid during 2005 of 1.7% (which is 28% higher than in 2004).

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

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

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

Lease operating expenses.    Lease operating expenses increased $6.7 million, or 36%, from 2003 due to increases in the number of producing wells and higher oilfield service costs. We incurred $2.4 million of costs associated with workovers in 2004 compared to $1.6 million in 2003. On a per unit basis, lease operating expenses increased $0.12 per Mcfe primarily due to higher field level costs.

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $4.2 million from 2003. Production taxes are paid primarily based on oil and gas sales and increased by $3.4 million from 2003. This increase was caused mostly by a 24% increase in prices and a 24% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.32 to $0.44 primarily due to higher prices. Gas handling charges increased by $0.7 million largely caused by increased production.

Depreciation, depletion and amortization.    DD&A of oil and gas properties increased $7.2 million, DD&A for property and equipment increased $0.5 million and the accretion for our asset retirement obligation increased $0.2 million for a total increase of $7.9 million, or 76%, from 2003. For oil and gas properties, $3.0 million of the increase was due to higher production volumes in 2004 and $4.2 million of the increase was due to an increase in the DD&A rate per equivalent unit of production in 2004. Our DD&A rate per equivalent unit of production increased by $0.28 per Mcfe to $0.96 primarily due to the addition of higher cost CO₂ tertiary

46

recovery reserves to our proved undeveloped reserves in 2004. DD&A on property and equipment increased due to acquisition of additional assets.

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

Interest expense.    Interest expense increased $2.0 million, or 50%, from 2003. An increase in outstanding debt in 2004 accounted for $1.7 million of the increase and an increase in interest rates accounted for the remainder.

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

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

Comparison of year ended December 31, 2003 to year ended December 31, 2002

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $31.5 million, or 74%, from 2002. The increase was due to the average realized price being 44% higher in 2003 and an increase of 21% in production volumes. The average price received for oil increased 21% to $29.92 per barrel and for gas increased 65% to $4.77 per Mcf compared to 2002. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $11.5 million from 2002. The effect of our hedging program decreased the average realized price by $0.80 per Mcfe in 2003 compared to a decrease of $0.06 per Mcfe in 2002.

Production volumes increased 21% (2,608 MMcfe) from 2002 due to our drilling program, additions from acquisitions and enhancements of our existing properties. Production volumes increased in our areas by 18% (2,003 MMcfe) in the Mid-Continent, 38% (250 MMcfe) in the Permian Basin, 106% (205 MMcfe) in East Texas, 77% (105 MMcfe) in North Texas, and 144% (99 MMcfe) in the Rocky Mountains. Production volumes declined 20% (54 MMcfe) in the Gulf Coast area.

Lease operating expenses.    Lease operating expenses increased $4.2 million, or 29%, from 2002 due to increases in the number of producing wells and higher oilfield service costs. We incurred $1.6 million of costs associated with workovers in 2003 compared to $0.3 million in 2002. On a per unit basis, lease operating expenses increased $0.08 per Mcfe primarily due to higher field level costs.

47

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $2.0 million from 2002. Production taxes are paid primarily based on oil and gas sales and increased by $1.7 million from 2002. This increase was caused mostly by a 44% increase in prices and a 21% increase in production. On a per Mcfe basis, production taxes increased from $0.25 to $0.32 primarily due to higher prices. Gas handling charges increased by $0.3 million primarily caused by higher production.

Depreciation, depletion and amortization.    DD&A increased $2.5 million, or 31%, from 2002 consisting of an increase in DD&A on oil and gas properties of $1.7 million, the accretion of our asset retirement obligation for the first year of implementation of $0.6 million and an increase in DD&A on property and equipment of $0.2 million. For oil and gas properties, $1.4 million of the increase was due to higher production volumes in 2003 and $0.3 million of the increase was due to an increase in the unit of production rate in 2003.

General and administrative expenses.    G&A expense increased by $0.9 million, or 22%, from 2002. The increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $3.1 million in 2003 and $3.1 million in 2002 capitalized as part of our exploration and development activities. On a per Mcfe basis, G&A expense was $0.32 in 2002 and 2003.

Interest expense.    Interest expense increased $0.1 million, or 3%, from 2002 of which $0.8 million was due to an increase in outstanding debt in 2003, offset by $0.7 million from a decrease in interest rates.

Income tax expense.    The effective tax rates for 2003 and 2002 were 38% and 36% respectively. The effective tax rate exceeds the federal statutory tax rate primarily due to state income taxes imposed by the various states where we have production offset partially by reductions for statutory depletion carryforwards and other items. Estimates of future taxable income can be significantly affected by changes in oil and gas prices, estimates of the timing and amount of future production and estimates of future operating expenses and capital costs.

Loss on discontinued operations.    During 2002, we sold a contract drilling business that we acquired in 2001. The asset group sold was distinguishable as a component of Chaparral, and the operating results of the contract drilling operations were reported as discontinued operations. For 2002, contract drilling revenues were approximately $3.0 million and the pretax loss was $0.9 million.

Liquidity and capital resources

Overview.    Our primary sources of liquidity are cash generated from our operations and our $450.0 million revolving credit line. At September 30, 2005, we had approximately $8.9 million of cash and cash equivalents, after the $42.1 million used to settle the CEI Bristol hedges on October 3, 2005, and $26.5 million of availability under our revolving credit line with a borrowing base of $270.0 million. At September 30, 2005, on a pro forma, as adjusted basis, after giving effect to our issuance of $325 million aggregate principal amount of 8 ¹/2% Senior Notes, we had approximately $113.0 million of availability under our revolving credit line with a borrowing base of $172.5 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, planned capital expenditures and contingencies for the next 12 months.

48

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.    As of September 30, 2005, we had incurred actual costs as summarized by area in the following table:

(Dollars in thousands)	Actual expenditures for the nine months ended September 30, 2005(1)		Percentage of total
Mid-Continent	$	40,373	37.9%
Permian Basin		27,107	25.4%
East Texas		18,917	17.7%
Gulf Coast		2,439	2.3%
North Texas		14,002	13.1%
Rocky Mountains		3,821	3.6%
	$	106,659	100.0%

(1) Includes $2.5 million of additions relating to increases in Chaparral’s asset retirement obligations.

In addition to the planned capital expenditures for oil and gas properties, we plan to spend approximately $7 million for acquisition and construction of new office and administrative facilities and equipment during 2005.

Our current 2006 capital expenditure budget for oil and gas properties is $200 million assuming this offering is consummated. Our budgeted capital expenditures for 2006 are detailed in the table below:

(in millions)	2006 budgeted capital expenditures		Percentage of total
Development activities:
Developmental drilling	$	82.0	41%
Enhancements		20.0	10%
Tertiary recovery		14.0	7%
Acquisitions		74.0	37%
Exploration activities		10.0	5%
Total	$	200.0	100%

49

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

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

Cash provided from operating activities.    Substantially all of our cash flow from operating activities is from the production and sale of oil and gas. We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the nine months ended September 30, 2005, the net cash provided from operations was approximately 47% of our net cash used in investing activities excluding the CEI Bristol acquisition. For the nine months ended September 30, 2005, cash flow from operating activities increased by 40% from the comparable period in the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense.

For the year ended December 31, 2004, the net cash provided from operations was approximately 52% of our net cash used in investing activities. For the year ended December 31, 2004, cash flow from operating activities increased by 53% from the prior year. The increase is due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense.

Our current credit facility.    We entered into a Sixth Restated Credit Agreement, which we refer to as our Credit Agreement, on June 22, 2005 which provides for a $450.0 million maximum commitment amount, is secured by our oil and gas properties and matures on June 22, 2009. Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. Prior to the acquisition of CEI Bristol, the borrowing base was increased from $235.0 million to $270.0 million on September 30, 2005. At September 30, 2005 we had an outstanding balance of $243.5 million under our Credit Agreement, and the borrowing base was $270.0 million. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of our additional debt issued in the offering of our 8 ¹/2% Senior Notes on December 1, 2005. As of January 31, 2006, we had $119.0 million outstanding under our Credit Agreement.

50

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2005 $217.5 million of our borrowings were Eurodollar loans and $26.0 million was an ABR loan. On October 5, 2005 the $26.0 million was converted to a Eurodollar loan.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. At September 30, 2005, the LIBOR rate was 4.14%, the Statutory Reserve Rate multiplier was 100% and the applicable margin was 2.00% resulting in an effective interest rate of 6.14% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus  ¹/2 of 1%; plus a margin where the margin varies from 0.00% to 0.50% depending on the utilization percentage of the borrowing base. At September 30, 2005 the applicable rate was 6.75% and the applicable margin was 0.50% resulting in an effective interest rate of 7.25% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense.

As of September 30, 2005 our weighted average interest rate on all borrowings under our Credit Agreement was 6.27%.

We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our Credit Agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. The agreement also requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 and a Minimum Debt Service Coverage Ratio, as defined in our Credit Agreement, of not less than 1.0. We believe we are in compliance with all covenants as of September 30, 2005.

51

The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in accordance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be useful as a measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At September 30, 2005 and December 31, 2004 our current ratio as computed using generally accepted accounting principles was 0.41 and 0.92, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.43 and 1.57, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

(Dollars in thousands)	December 31, 2004			September 30, 2005
Current assets per GAAP	$	52,499		$	133,490
Plus—Availability under Credit Agreement		20,611			25,500
Less—Deferred tax asset on hedges and asset retirement obligation		(5,291	)		(32,882	)
Less—Current assets of CEI Bristol		—			(52,207	)
Less—Short term hedge instruments		—			(103	)
Current assets as adjusted	$	67,819		$	73,798
Current liabilities per GAAP	$	57,185		$	326,773
Less—Short term hedge instruments		(13,810	)		(136,603	)
Less—Short term asset retirement obligation		(262	)		(1,382	)
Less—Other current liabilities of CEI Bristol		—			(5,316	)
Less—GE Bridge Loan		—			(132,000	)
Current liabilities as adjusted	$	43,113		$	51,472
Current ratio for loan compliance		1.57			1.43

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

Our 8 ¹/2% Senior Notes due 2015.    On December 1, 2005, we sold $325.0 million aggregate principal amount of 8 ¹/2% Senior Notes maturing on December 1, 2015. There is no sinking fund for the 8 ¹/2% Senior Notes. The 8 ¹/2% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 ¹/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries.

52

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

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

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

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

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

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

• incur additional indebtedness;

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

• make investments;

• incur liens;

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

• engage in transactions with our affiliates;

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

• consolidate, merge or transfer assets.

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

Alternative capital resources.    We have historically used cash flow from operations and secured bank financing as our primary sources of capital. In the future we may use additional sources such as asset sales, public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

53

Contractual obligations.    The following table summarizes our contractual obligations and commitments as of December 31, 2004:

(Dollars in thousands)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:
Revolving credit line—including estimated interest expense(1)	$	7,241	$	168,009	$	—	$	—	$	175,250
Other long-term notes—including estimated interest expense(2)		2,192		5,287		745		6,732		14,956
Capital leases—including estimated interest		589		285		19		—		893
Operating leases		450		75		—		—		525
Abandonment obligations		262		4,308		127		5,627		10,324
Derivative obligations		13,810		7,425		—		—		21,235
Total	$	24,544	$	185,389	$	891	$	12,359	$	223,183

(1) On a pro forma basis to reflect the offering of our 8 ¹/2% Senior Notes, as of September 30, 2005, the amount of the revolving credit line due in 3-5 years, excluding estimated interest expense, would be $59.5 million and the total amount would be $59.5 million.

(2) On a pro forma basis to reflect the offering of our 8 ¹/2% Senior Notes, our other long-term notes more than 5 years and the total amount would be increased by $325.0 million, excluding estimated interest expense.

Critical accounting policies and estimates

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

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

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

54

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

Oil and gas properties.

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

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

Our proved reserve information included in this prospectus is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 75% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2004 and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

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

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

55

• Costs not subject to amortization.    Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. At December 31, 2004 we had approximately $5.0 million of costs excluded from the amortization base. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

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

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

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

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

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

56

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

Recent accounting pronouncements

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

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments”, or SFAS 123R. SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. We will adopt this statement in our first reporting period in 2006. We are currently in the process of assessing the impact of adopting this new standard.

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

Effects of inflation and pricing

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

Quantitative and qualitative disclosures regarding market risks

Oil and gas prices.    Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and

57

our ability to obtain capital for our acquisition, exploration and development activities. Based on our year ended December 31, 2004 production, our gross revenues from oil and gas sales would change approximately $1.2 million for each $0.10 change in gas prices and $1.2 million for each $1.00 change in oil prices.

We periodically enter into derivative contracts, consisting primarily of swaps, to manage our exposure to decreases in oil and gas prices. When using swaps to hedge our oil and gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133 which allows the aggregate change in fair value to be recorded as accumulated other comprehensive income (loss) on the consolidated balance sheet. Recognition in the income statement occurs in the period of contract settlement. Our Credit Agreement allows us to hedge up to 80% of our expected future production for three years. Our outstanding hedges as of September 30, 2005 are summarized below:

	Natural gas					Crude oil
Period	Total MMcf	Weighted average fixed price to be received		Percent of PDP production hedged		Total MBbl	Weighted average fixed price to be received		Percent of PDP production hedged
10/2005 to 12/2005	3,490	$	7.55	75.3	%	315	$	38.26	70.1	%
01/2006 to 03/2006	3,330		8.30	75.4		282		38.06	71.6
04/2006 to 06/2006	3,180		6.79	76.0		273		38.74	72.0
07/2006 to 09/2006	3,090		6.78	77.4		267		41.36	72.8
10/2006 to 12/2006	2,670		7.76	70.4		255		44.46	71.7
01/2007 to 03/2007	2,460		8.49	63.8		222		45.86	68.1
04/2007 to 06/2007	2,460		6.94	66.1		216		45.68	68.3
07/2007 to 09/2007	2,460		6.94	68.4		174		48.75	56.6
10/2007 to 12/2007	1,260		8.56	36.1		108		53.86	36.1
01/2008 to 03/2008	810		9.99	24.5		39		63.75	14.1
04/2008 to 06/2008	720		8.05	22.5		39		63.40	14.5
07/2008 to 09/2008	360		8.03	17.3		4		61.66	4.5

Interest rates.    All of the outstanding borrowings under our Credit Agreement as of September 30, 2005 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

58

Business and properties

Our business

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma.

Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to developmental drilling. As of December 31, 2004, approximately 87% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties. On September 30, 2005, we acquired the 99% limited partner interest in CEI Bristol for $158 million. We have managed this limited partnership since 2000. The following discussion excludes the effects of the CEI Bristol acquisition in September 2005 except where specifically stated.

As of December 31, 2004, on a pro forma basis we had estimated proved reserves of 606 Bcfe and a PV-10 value of $1,010.3 million. For the nine months ended September 30, 2005, on a pro forma basis, our average daily production was 80.9 MMcfe, a 14% increase over the comparable period in 2004. As of December 31, 2004, on a pro forma basis, our estimated reserve life would have been 22.7 years. On a pro forma basis, our revenues and Adjusted EBITDA for the year ended December 31, 2004 were $125.6 million and $82.7 million, respectively. For the nine months ended September 30, 2005, on a pro forma basis, our revenue and Adjusted EBITDA were $107.9 million and $79.0 million, respectively. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of a standardized measure of discounted future net cash flows to PV-10 value, and our definition of Adjusted EBITDA (a non-GAAP measure) and a reconciliation of our income from continuing operations before accounting change to Adjusted EBITDA, beginning on page 13.

For the period from 2001 to 2004, our proved reserves and production have grown at a compounded annual growth rate of 41% and 20%, respectively. We have grown primarily through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

We have a multi-year inventory of drillable prospects and an active drilling program. We have identified over 700 proved developmental drilling locations, as well as over 2,200 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our current drilling rate. We normally have three to six drilling rigs active at any time, depending on the availability of rigs. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted one proprietary shoot and are currently permitting on two additional proprietary 3-D shoots.

Our capital expenditures for oil and gas properties for the nine months ended September 30, 2005 were $104.2 million (excluding the acquisition of the limited partner interest in CEI Bristol

59

Acquisition, L.P.), representing a 51% increase over the comparable period in 2004. Our capital expenditure budget for oil and gas properties for 2006 is $200 million. We have budgeted approximately 58% of our 2006 capital expenditures on development activities (drilling—41%, enhancements—10% and tertiary recovery—7%), 37% for acquisitions and 5% for exploration activities. A majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO₂) tertiary recovery projects in the Mid-Continent and Permian Basin.

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

Business strengths

Consistent track record of low-cost reserve additions and production growth.    From 2001 to 2004, we have grown reserves and production by a compounded annual growth rate of 41% and 20%, 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 610%, 468% and 1,219% of our production in 2002, 2003 and 2004, respectively, at a fully developed average F&D cost of $1.31 per Mcfe over this three year period, which we believe is among the lowest in the industry.

Disciplined approach to acquisitions.    We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence, with reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2002, 2003 and 2004, our capital expenditures for acquisitions were $17.7 million, $19.9 million and $30.5 million, respectively. These acquisition capital expenditures represented approximately 43%, 35% and 32%, respectively, of our total capital expenditures for those years. In 2005 we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added, as of September 30, 2005, an estimated 115 Bcfe of proved reserves. Not including the acquisition of CEI Bristol, we spent $37.3 million on acquisitions during the first nine months of 2005, representing approximately 36% of our total capital expenditures for that period. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

Property enhancement expertise.    Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation

60

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, 2004, we had an inventory of over 700 proved developmental drilling locations and over 2,200 additional potential drilling locations. Not including the CEI Bristol acquisition, we spent $52.1 million on development and exploration drilling for the first nine months of 2005. We have experienced a high historical drilling success rate of approximately 90% on a weighted average basis during 2002, 2003 and 2004. For 2006, we have budgeted $92 million to drill more than 55 operated wells and to participate in more than 130 wells operated by others. We utilize 3-D seismic data to help identify additional reserve targets in, around and under older producing fields.

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO₂ enhanced oil recovery. CO₂ enhanced oil recovery involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO₂ tertiary recovery operations, as well as specific software for modeling CO₂ enhanced recovery. We own a 29.2% interest in and operate a large CO₂ tertiary flood unit in southern Oklahoma and installed a second tertiary flood unit in the Oklahoma panhandle. We have subsequently acquired other related assets, and our proved reserves at December 31, 2004 include 14 properties, two with both proved developed producing and proved undeveloped and twelve with proved undeveloped only, that will utilize CO₂ tertiary recovery methods. These proved developed producing and proved undeveloped CO₂ tertiary recovery projects included in our proved reserves accounted for approximately 26% of our December 31, 2004 total proved reserves.

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 33 years after starting his career at Exxon as petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 21 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Individuals in our 24-person management team have an average of over 24 years of experience each in the oil and gas industry.

Business strategy

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

Continue lower-risk development drilling program.    We have allocated $82 million, or 41% of our 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in

61

increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. We generally pursue mature properties in the second half of their life which are located in proven fields in which we have an opportunity to improve operations through cost control, and to increase production and reserves through the application of improved technology and additional drilling. Excluding the CEI Bristol acquisition, which was larger than our typical acquisitions, we have spent approximately $37.3 million on acquisitions through September 30, 2005. Our 2006 acquisition capital budget is $74 million, or 37% of our total capital expenditure budget.

Apply technical expertise to enhance mature properties.    Once we acquire a property and become its 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 14 field offices throughout Oklahoma and Texas. 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, 2004, we had an inventory of 221 developed enhancement projects requiring total estimated capital expenditures of $9 million.

Expand CO₂ enhanced oil recovery activities.    We have accumulated interests in 45 fields in Oklahoma and Texas that meet the criteria for CO₂ tertiary recovery operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in a number of these fields. Four of our CO₂ projects in our proved reserves are scheduled to initiate CO₂ injection in 2006. We have a 100% ownership interest in 86 miles of CO₂ pipeline and control a 50% or larger ownership interest in an additional 160 miles of CO₂ pipeline. The planned construction of 88 miles of CO₂ pipeline will facilitate CO₂ injection in these new projects. We have budgeted $14 million in 2006 towards these projects. To support our existing CO₂ tertiary oil recovery projects, we currently inject approximately 37 MMcf per day of CO₂.

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 approximately 5% of our 2006 capital expenditures on exploratory drilling.

Control operations and costs.    We generally 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. Operations are crucial to the implementation of our programs and, accordingly, we are willing to take additional measures to become the operator. As of December 31, 2004, we operated properties comprising approximately 84% of our proved reserves.

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. Excluding PDP production attributable to the CEI Bristol acquisition, as of September 30, 2005, we had hedges in place for approximately 77%, 55% and 5% of our estimated PDP gas production

62

for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 78%, 61% and 6% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities during each of the past three years as commodity prices have increased.

Properties

The following tables present proved reserves and PV-10 value as of December 31, 2004, and average daily production for the year ended December 31, 2004 and nine months ended September 30, 2005 by major areas of operation for Chaparral and CEI Bristol.

	Proved reserves as of December 31, 2004						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, 2004	Nine months ended September 30, 2005
Chaparral
Mid-Continent	31,015	193,916	380,006	73.7%	$	586.7	40.6	46.6
Permian Basin	5,532	37,656	70,848	13.7%		129.0	6.2	8.1
East Texas	1,030	20,095	26,275	5.1%		49.5	2.1	5.4
North Texas	2,810	386	17,246	3.3%		40.4	1.6	2.0
Rocky Mountains	1,241	3,206	10,652	2.1%		19.5	0.6	1.6
Gulf Coast	386	7,392	9,708	1.9%		18.2	1.0	1.5
Other	13	969	1,047	0.2%		1.8	—	—
Chaparral total	42,027	263,620	515,782	100.0%	$	845.1	52.1	65.2
CEI Bristol
Mid-Continent	913	39,165	44,643	49.6%	$	79.0	14.9	9.8
Permian Basin	974	19,948	25,792	28.6%		48.6	2.1	2.1
East Texas	102	8,567	9,179	10.2%		16.9	0.6	1.3
North Texas	357	302	2,444	2.7%		4.0	0.4	0.5
Rocky Mountains	176	1,414	2,470	2.7%		3.6	0.8	0.6
Gulf Coast	318	3,643	5,551	6.2%		13.1	1.6	1.4
CEI Bristol total	2,840	73,039	90,079	100.0%	$	165.2	20.4	15.7
Pro forma total	44,867	336,659	605,861		$	1,010.3	72.5	80.9

Our properties have relatively long reserve lives and highly predictable production profiles. Based on our December 31, 2004 proved reserves and 2004 production, our reserve life was 27 years. As of December 31, 2004 on a pro forma basis, our estimated reserve life would have been 22.7 years. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and gas properties is geographically diversified, 90% of our 2004 production was concentrated in our core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2004 we owned interests in 4,772 gross (1,161 net) producing wells and we operated wells representing 84% 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.

63

The following summaries do not include the effects of the CEI Bristol acquisition.

Mid-Continent

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2004, accounted for 73.7% of our proved reserves and 69.4% of our PV-10 value. On a pro forma basis at December 31, 2004, the Mid-Continent Area accounted for 70.1% of our proved reserves and 65.9% of our PV-10 value. We own an interest in 3,114 wells in the Mid-Continent, of which we operate 1,047. Our three largest properties and 13 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the nine months ended September 30, 2005, our net average daily production in the Mid-Continent Area was approximately 46.6 MMcfe per day, or 71.5% 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 2.2% of our proved reserves and 3.3% of the PV-10 value of our proved reserves at December 31, 2004. 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 16.4 MMBbl of primary reserves and 13.4 MMBbl of secondary reserves. There are approximately 30 active producing wells in this area. Currently CO₂ injection operations are under way in the Phase I area of the Camrick Unit. CO₂ injection has improved the production in the Camrick Unit from approximately 100 Bbls per day in 2001 to approximately 825 Bbls per day as of August 2005. We currently plan to expand CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma.    SWAGSU represents 2.6% of our proved reserves and 2.8% of the PV-10 value of our proved reserves at December 31, 2004. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1966, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have approximately 21 active producing wells in this unit. During the last twelve months, we have drilled three wells and are scheduled to drill one additional well and re-enter three additional abandoned wells.

Cleveland Sand Play—Ellis County, Oklahoma.    We control approximately 5,190 acres in the Cleveland Sand Play. The Cleveland Sand occurs at 8,300 feet and is considered a tight gas sand reservoir. We currently have interests in 18 Cleveland Sand producing wells, have drilled four wells in 2005 and have plans to drill five wells in 2006. Horizontal drilling technology has been employed in two recently drilled wells. Recovery is expected to be 1.4 Bcfe per horizontal well. Future wells will utilize a mix of vertical and horizontal technology.

64

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma.    The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO₂ injection program was initiated in 1982. This miscible CO₂ injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996 miscible CO₂ injection began in the downdip section of the Sims C2. We have approximately 89 active producing wells in this unit.

Harmon County 3-D Shoot—Harmon County, Oklahoma.    Chaparral has leased in excess of 29,000 acres in Harmon County, Oklahoma and will begin a proprietary 3-D seismic shoot on this acreage in December 2005. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling is expected to start in mid-2006 with the potential to drill 150 wells.

CO₂ Enhanced Recovery Operations—Various counties, Oklahoma and Texas.    We have accumulated 45 fields in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations. Four of these fields are scheduled to initiate CO₂ injection within the next year. We have a 100% ownership and operate 86 miles of CO₂ pipeline. We also control a 50% or larger ownership interest in an additional 160 miles of pipeline. To facilitate the expansion of our CO₂ enhanced oil recovery program to the eight fields currently budgeted in 2006 and 2007, we will be extending our CO₂ pipeline infrastructure by 88 miles. We are negotiating transportation and supply agreements to provide the necessary CO₂ for these projects. With this expansion, we expect to increase our CO₂ volumes transported to 30 MMcf per day by July 2006 and to in excess of 75 MMcf by July 2007. Arrangements to secure additional sources of CO₂ are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in April 2005 estimating that significant oil reserves could be technically recovered in the State of Oklahoma through CO₂ enhanced oil recovery processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2004, accounted for 13.7% of our proved reserves and 15.3% of our PV-10 value. On a pro forma basis at December 31, 2004, the Permian Basin Area accounted for 16.0% of our proved reserves and 17.6% of our PV-10 value. We own an interest in 450 properties in the Permian Basin, of which we operate 246. Six of our 20 largest properties, in terms of PV-10 value, are located in this area. During the nine months ended September 30, 2005, our net average daily production in the Permian Basin Area was approximately 8.1 MMcfe per day, or 12.4% 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.    The Tunstill Field Play covers approximately 6,480 acres. We operate these wells with a working interest of 100%. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 feet. Older wells produce from 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.

65

During the nine months ended September 30, 2005, we have drilled nine wells in this play. We have identified 31 potential drilling locations in this play. We have recently acquired through a farmout from Chevron approximately 12,880 acres that are adjacent to the existing Tunstill field play.

Haley Area Strawn and Morrow Play—Loving County, Texas.    The Haley Area Strawn and Morrow Play encompasses 3,200 acres. We own interests in and operate five producing wells in this play. Production has been established from two main intervals: the Strawn at a depth of approximately 15,500 feet and the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Strawn and the other three wells are completed in the Morrow. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. We are currently drilling one well, completing a recently drilled well and have three more scheduled for 2006. We anticipate drilling costs for these proposed wells of $8.5 million per well. Development is eventually expected to be on a 160 acre pattern.

East Texas

East Texas is one of our four growth areas and, as of December 31, 2004, accounted for 5.1% of our proved reserves and 5.9% of our PV-10 value. On a pro forma basis at December 31, 2004, East Texas accounted for 5.9% of our proved reserves and 6.6% of our PV-10 value. We own an interest in 170 properties in East Texas, of which we operate 138. These reserves are characterized by shorter life and higher initial potential.

Giddings North Edwards—Fayette County, Texas.    We control 4,780 acres in the Gidding North Edwards Field. We operate this field with an average working interest of 98%. Eight wells are producing from the Edwards Lime that occurs at a depth of 10,100 feet. These eight wells have produced 554 MBbls of oil and 42.3 Bcf of natural gas. We have scheduled an Edwards test in this field. We are currently leasing on an additional 1,000 acres adjacent to this field and anticipate two more Edwards wells could be drilled on this acreage.

Winnsboro Field—Wood County, Texas.    We control approximately 1,072 acres in the Winnsboro Field and operate 11 wells. Primary objectives in this field are the Travis Peak and Cotton Valley that occur at depths from 8,600 to 10,300 feet. Additional potential pay zones are the Sub-Clarksville, Bacon Lime, Hill, Gloyd and the Pettit-Pittsburg that occur at depths from 4,150 to 8,500 feet. During the last 12 months we have drilled two development wells in this field. We have plans to drill several more development wells in this play.

North Texas

North Texas is the second of our four growth areas and, as of December 31, 2004, accounted for 3.3% of our proved reserves and 4.8% of our PV-10 value. On a pro forma basis at December 31, 2004, North Texas accounted for 3.2% of our proved reserves and 4.4% of our PV-10 value. We own an interest in 107 properties in North Texas, of which we operate 74. One of our three proprietary 3-D seismic shoots has been completed in this area.

Percy Jones Clearfork Play—Howard and Mitchell Counties, Texas.    We own and operate the Percy Jones, Percy Jones A and Percy Jones B leases, encompassing 640 acres in the Laton East Howard Field. We currently operate these properties with an average working interest of 100%. A total of 54 wells have been completed in the Glorieta at depths of 2,500 feet and Upper

66

Clearfork at depths of 2,700 feet since its discovery in 1947. The Percy Jones lease (north half of Section 13) has a total of 44 producing wells and is developed on 10 acre spacing with some increased density development to 5 acres and cumulative production of 1.8 MMBbls of oil and 24 MMcf of natural gas. The Percy Jones A and B leases make up the south half of the section, have a total of 10 existing wells and have cumulative production of 365 MBbls of oil and 22 MMcf of natural gas. Secondary recovery through water injection has proven successful in offset leases but has been done on a very limited basis in the Percy Jones lease.

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

Since June 2004, we have drilled six wells in the north half of the section and nine wells in the south half with initial production from 15 to 130 Bbls of oil per day. In addition, we have identified 28 PUD locations and 43 probable locations.

Eanes Units—Montague County, Texas.    We own and operate the North Eanes, East Eanes and South Eanes Units. These units cover approximately 7,000 acres and produce from the Caddo at approximately 5,600 feet. We currently operate these units with an average working interest of 95%. We have conducted an 11.5 square mile proprietary 3-D seismic program in these units. Potential pay zones have been identified in the Caddo at 5,600 feet, Atoka at 5,700 feet, Mississippian Reef at 6,300 feet, Viola at 6,500 feet and the Ellenberger at 6,800 feet. We have approximately 20 active producing wells in this area. We have drilled five wells and have one additional well drilling. We may drill up to 36 additional wells if this initial drilling effort proves successful.

Rocky Mountains

The Rocky Mountains is our third growth area and, as of December 31, 2004, accounted for 2.1% of our proved reserves and 2.3% of our PV-10 value. On a pro forma basis at December 31, 2004, the Rocky Mountains accounted for 2.2% of our proved reserves and 2.3% of our PV-10 value. We own 97 properties in the Rocky Mountains Area, of which we operate 36. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

Bakken Horizontal Play—Richland County, Montana.    We are currently pursuing acreage in Richland County, Montana. We recently drilled a dual leg horizontal well on acreage we own that was producing from the Red River formation. The McVay #2-34H well was drilled as a horizontal dual leg lateral with the first lateral measuring 3,648 feet in length and the second lateral measuring 3,496 feet in length. During August 2005, the well was producing 313 Bbls of oil per day and 190 Mcf of natural gas per day.

We recently leased approximately 8,000 acres in the immediate area of the McVay #2-34H and have five wells scheduled to be drilled in 2006.

Gulf Coast

Our fourth growth area is the Gulf Coast and, as of December 31, 2004, accounted for 1.9% of our proved reserves and 2.2% of our PV-10 value. On a pro forma basis at December 31, 2004, the

67

Gulf Coast Area accounted for 2.5% of our proved reserves and 3.1% of our PV-10 value. We own 195 properties in the Gulf Coast, of which we operate 99. 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 with our long-life reserves adds a dimension for increasing our near-term cash flow.

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

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

Oil and natural gas reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2004. Information in the table is derived from reserve reports of estimated proved reserves on the top 75% of our non CO₂ enhanced oil recovery proved undeveloped reserves prepared by Cawley, Gillespie & Associates, Inc. (62% of PV-10 value) and by Lee Keeling & Associates, Inc. for our CO₂ enhanced oil recovery proved undeveloped reserves (13% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (25% of PV-10 value).

	Net proved reserves
	Natural gas (MMcf)	Oil (MBbl)	Total (MMcfe)	PV-10 value (In thousands)
Developed—producing	157,724	15,346	249,800	$	459,115
Developed—non-producing	28,820	2,012	40,892		76,204
Undeveloped	77,076	24,669	225,090		309,745
Total proved	263,620	42,027	515,782	$	845,064

The reserve life as of December 31 2002, 2003 and 2004 was 19.6, 19.9, and 27.2 years, respectively. The reserve life was calculated by dividing total proved reserves by production volumes for the year indicated.

68

The following table sets forth the estimated future net revenues from proved reserves, the present value of those revenues and the prices used in projecting them over the past three years:

(Dollars in thousands, except prices)	2002		2003		2004
Future net revenue	$	658,710	$	1,053,624	$	1,903,785
PV-10 value		320,648		488,305		845,064
Standardized measure of discounted future net cash flows		218,266		325,250		556,526
Oil price (per Bbl)	$	31.23	$	32.52	$	43.51
Natural gas price (per Mcf)	$	4.59	$	6.19	$	6.35

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, 2004 relating to the producing wells in which we owned a working interest as of that date. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells is the total number of producing wells in which we have an interest, and net wells is the sum of our working interest in all wells.

	Total wells
	Gross	Net
Crude oil	2,406	568
Natural gas	2,366	593
Total	4,772	1,161

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2004.

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Mid-Continent	781,994	263,975	25,312	15,770
Permian Basin	73,515	34,919	807	698
East Texas	27,710	19,374	223	168
North Texas	17,620	9,656	1,675	1,257
Rocky Mountains	31,030	5,461	40	10
Gulf Coast	43,267	7,214	335	251
Total	975,136	340,599	28,392	18,154

69

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.

	2002		2003		2004
	Gross	Net	Gross	Net	Gross	Net
Development wells
Productive	74.0	12.2	87.0	23.9	127.0	37.1
Dry	6.0	2.1	2.0	0.7	5.0	2.8
Exploratory wells
Productive	2.0	0.5	2.0	1.4	1.0	0.1
Dry	4.0	2.9	—	—	—	—
Total wells
Productive	76.0	12.7	89.0	25.3	128.0	37.2
Dry	10.0	5.0	2.0	0.7	5.0	2.8
Total	86.0	17.7	91.0	26.0	133.0	40.0
Percent productive	88%	72%	98%	97%	96%	93%

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

	Year ended December 31,
	2002		2003		2004
Production:
Oil (MBbl)		791		924		1,173
Natural gas (MMcf)		7,952		9,762		11,923
Combined (MMcfe)		12,698		15,306		18,961
Average daily production:
Oil (Bbls)		2,167		2,532		3,214
Natural gas (Mcf)		21,786		26,745		32,666
Combined (Mcfe)		34,788		41,937		51,950
Average prices (before effect of hedges):
Oil (per Bbl)	$	24.73	$	29.92	$	40.53
Natural gas (per Mcf)		2.90		4.77		5.54
Combined (per Mcfe)		3.36		4.85		5.99
Average costs per Mcfe:
Lease operating	$	1.14	$	1.22	$	1.34
Production tax and gas handling charges	$	0.29	$	0.37	$	0.52
Depreciation, depletion, and amortization	$	0.62	$	0.68	$	0.96
General and administrative	$	0.32	$	0.32	$	0.32

70

Competition

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

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

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

Markets

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

• the amount of crude oil and natural gas imports;

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

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

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

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

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

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

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

71

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

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

Environmental matters and regulation

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

General

Our operations, like the operations of other companies in our industry, are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

• require the acquisition of various permits before drilling commences;

• require the installation of expensive pollution control equipment;

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

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

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

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

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

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly

72

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, 2004, 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 2005 or that will otherwise have material impact on our financial position or results of operations.

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

National Environmental Policy Act

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

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

Waste handling

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

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

73

Comprehensive Environmental Response, Compensation and Liability Act

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

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

Water discharges

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

Air emissions

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

74

Other laws and regulation

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

Other regulation of the oil and gas industry

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

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

Drilling and production

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

• the location of wells;

• the method of drilling and casing wells;

• the rates of production or “allowables”;

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

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In

75

some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural gas sales transportation

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

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

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

Natural gas gathering regulations

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

State regulation

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits.

76

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

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

Seasonality

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

Legal proceedings

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

Title to properties

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

Employees

As of September 30, 2005, we had 319 full-time employees, including 8 geologists and geophysicists, 21 production and reservoir engineers and 8 land professionals. Of these, 192 work in our Oklahoma City office and 127 are in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

77

Management

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

Executive officers and directors

The following table provides information regarding our executive officers and directors:

Name	Age	Position
Mark A. Fischer	56	Chairman, Chief Executive Officer and President
Charles A. Fischer, Jr.	57	Chief Administrative Officer, Executive Vice President and Director
Joseph O. Evans	51	Chief Financial Officer and Executive Vice President
Robert W. Kelly II	47	Senior Vice President and General Counsel
Larry E. Gateley	56	Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	43	Senior Vice President—Operations and Production Engineering

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

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

78

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

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

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

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

79

Board structure and compensation of directors

Upon completion of the offering, our board of directors will consist of three members. Our board has determined that Mr.              is independent under the applicable rules of the                     . 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 will be independent directors. Following the phase-in period, our board of directors will consist of seven members, three of which will be independent.

Our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2007, 2008 and 2009, respectively. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Directors who are also full-time officers or employees of our company will receive no additional compensation for serving as directors. All other directors will receive an annual retainer of $            . Each non-employee director also will receive a fee of $             for each board meeting attended and $             for each committee meeting attended. In addition, the chairman of the audit committee will receive an annual fee of $            , the chairman of the compensation committee will receive an annual fee of $             and the chairman of the nominating and governance committee will receive an annual fee of $            .

Board committees

Our board of directors plans to have an audit committee, a nominating and governance committee and a compensation committee following this offering. Following the phase-in period permitted under the NYSE rules, we intend that all the members of our nominating and governance committee and of our compensation committee will be independent under applicable provisions of those rules. In addition, we intend that the members of our audit committee will be independent under applicable provisions of the Securities Exchange Act of 1934 and the NYSE rules following the phase-in period.

Audit Committee.    The audit committee, which is expected to consist of Messrs.              (chair),              and             , 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.

Nominating and Governance Committee.    The nominating and governance committee, which is expected to consist of Messrs.                  (chair),              and             , 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.

80

Compensation Committee.    The compensation committee, which is expected to consist of Messrs.             (chair),                  and             , 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.

Web access

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

Compensation committee interlocks and insider participation

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

Compensation of executive officers

The following table summarizes all compensation earned by our Chief Executive Officer and our four other most highly compensated executive officers during the year ended December 31, 2004, to whom we refer in this prospectus as our named executive officers. The following table does not include Joseph O. Evans, our Chief Financial Officer who joined us in July 2005.

Summary compensation table

		Annual Compensation
	Year	Salary		Bonus		All Other Compensation(1)(2)
Mark A. Fischer	2004	$	201,322	$	12,097	$	22,021
Chairman, Chief Executive Officer and President
Charles A. Fischer, Jr.	2004	$	159,662	$	9,825	$	12,928
Chief Administrative Officer, Executive Vice President and Director
Robert W. Kelly II	2004	$	136,292	$	8,747	$	7,252
Senior Vice President and General Counsel
Larry E. Gateley	2004	$	149,791	$	9,267	$	7,953
Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	2004	$	131,423	$	7,897	$	43,229
Senior Vice President—Operations and Production Engineering

(1) Includes: for Mark A. Fischer, $13,407 reflecting allocable expenses for personal use of aircraft and vehicles and $8,614 in Chaparral matching 401(k) contributions; for Charles A. Fischer, Jr., $4,456 reflecting allocable expenses for personal use of aircraft and vehicles and $8,472 in Chaparral matching 401(k) contributions; for Robert W. Kelly II, $7,252 in Chaparral matching 401(k) contributions; for Larry E. Gateley, $7,953 in Chaparral matching 401(k) contributions; and for James M. Miller, $37,774 in payments pursuant to overriding royalty interests subject to vesting and $5,455 in Chaparral matching 401(k) contributions.

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

81

Phantom unit plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, or the Plan, to provide deferred compensation to certain key employees as the participants. Phantom units may be awarded to participants in total up to 2% of the fair market value of Chaparral, as defined by the Plan. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with us due to death, disability, retirement or termination by Chaparral without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Compensation expense is recognized over the vesting period of the phantom units. We recognized deferred compensation expense of $120,000 for the year ended December 31, 2004 related to the Plan.

Employment agreements

We have agreed to pay Joseph O. Evans an annual salary of $212,000 and an aggregate bonus of not less than $50,000 for his first year of employment with us. 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 this offering on the adoption of a revised severance package by the compensation committee.

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

Indemnification agreements

We have also entered into indemnification agreements with all of our directors and some of our executive officers. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of the State of

82

Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

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

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

• us, except for:

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

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

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

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

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

83

Principal and selling stockholders

The following table sets forth information, as of December 15, 2005, 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, by all directors and executive officers as a group, and each selling stockholder. The number of shares in the column “Number of Shares Offered” represents all of the shares that each selling stockholder may offer under this prospectus assuming no exercise of the underwriters’ over-allotment option. Except as noted below in the footnotes, the selling stockholders will each sell a pro rata number of the total shares that may be sold pursuant to the underwriters’ over-allotment option. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. None of the selling stockholders are broker dealers or affiliates of broker dealers. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act.

	Shares beneficially owned prior to this offering		Number of Shares Offered	Shares beneficially owned after this offering
Name(1)	Number	Percent		Number	Percent
Mark A. Fischer(2)		50%			%
Altoma Energy G.P.(3)		50%			%
Charles A. Fischer, Jr.(4)		50%			%
Joseph O. Evans	—	—			—
Robert W. Kelly II	—	—			—
Larry E. Gateley	—	—			—
James M. Miller	—	—			—
All Directors and Officers as a group (6 persons)		100%			%

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

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

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

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

84

Certain relationships and related transactions

CEI Bristol

Prior to September 30, 2005 Chaparral managed and administered the business of CEI Bristol Acquisition, L.P. At December, 2003 and 2004, we had accounts receivable of approximately $5,332,000 and $1,441,000, respectively, due from CEI Bristol. Chaparral acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were approximately $939,000 and $1,018,000 for the years ended December 31, 2003 and 2004, respectively. Additionally, we were compensated for management services provided to CEI Bristol through a management fee. Management fees earned by Chaparral were approximately $89,000 and $228,000 for the years ended December 31, 2003 and 2004, respectively. On September 30, 2005 we acquired the 99% limited partner interest in CEI Bristol Acquisition L.P. and therefore will no longer receive any of these fees.

Participation interests

Historically, Chaparral has granted participation interests in the form of overriding royalty interests to a limited number of employees. Chaparral has also granted pro rata certain overriding royalty interests to its stockholders or their affiliates, including Mark A. Fischer and Charles A. Fischer, Jr. We believe that the granting of these participation interests to our employees in certain prospects promotes in them a proprietary interest in our exploration efforts for the benefit of us and our stockholders. Aggregate payments on these interests to all persons were $252,553, $314,251 and $522,965 in 2002, 2003 and 2004, respectively. Payments on these interests to Mark A. Fischer were $83,619, $82,999 and $130,509 in 2002, 2003 and 2004, respectively. Payments on these interests to Charles A. Fischer, Jr. were $22,068, $21,572 and $34,421 in 2002, 2003 and 2004, respectively. We made grants of additional overriding royalty interests in 2005.

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

Port Aransas property

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

85

Offering by selling stockholders

We are paying the expenses of the offering by the selling stockholders, including a single firm of attorneys for the selling stockholders. We will not be paying the underwriting discounts, commissions and taxes with respect to shares of common stock sold by the selling stockholders and the fees and expenses of any other attorneys, accountants and other advisors separately retained by them.

Registration rights agreement

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

86

Description of capital stock

Upon the completion of this offering, our authorized capital stock will consist of:

•              shares of common stock, $0.01 par value; and

•              shares of preferred stock, $0.01 par value, none of which are currently designated.

Upon the completion of this offering,              shares of common stock and no shares of preferred stock will be outstanding.

The following summarizes the material provisions of our capital stock and important provisions of our certificate of incorporation and bylaws. This summary is qualified by our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus is a part and by the provisions of applicable law.

Common stock

Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Because holders of common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election. The holders of common stock are entitled to receive dividends as may be declared by the board of directors. Upon our liquidation, dissolution or winding up, and subject to any prior rights of outstanding preferred stock, the holders of our common stock will be entitled to share pro rata in the distribution of all of our assets available for distribution to our stockholders after satisfaction of all of our liabilities and the payment of the liquidation preference of any preferred stock that may be outstanding. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable. The holders of our common stock will have no preemptive or other subscription rights to purchase our common stock.

Preferred stock

Subject to the provisions of the certificate of incorporation and limitations prescribed by law, the board of directors will have the authority to issue up to              shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions of the preferred stock, including dividend rights, dividend rates, conversion rates, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of the series, which may be superior to those of the common stock, without further vote or action by the stockholders. We have no present plans to issue any shares of preferred stock.

One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and, as a result, protect the continuity of our management. The issuance of shares of the preferred stock under the board of directors’ authority described above may adversely affect the rights of the holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of

87

common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock or may otherwise adversely affect the market price of the common stock.

Provisions of our certificate of incorporation and bylaws

Written consent of stockholders

Our certificate of incorporation and bylaws provide that any action required or permitted to be taken by our stockholders must be taken at a duly called meeting of stockholders and not by written consent.

Amendment of the Bylaws

Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by the holders of not less than 66 ²/3% of the voting power of all outstanding voting stock.

Special meetings of stockholders

Our bylaws preclude the ability of our stockholders to call special meetings of stockholders.

Other limitations on stockholder actions

Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. In addition, the ability of our stockholders to remove directors without cause is precluded.

Classified Board

Only one of three classes of directors is elected each year. See “Management—Board of Directors.”

Limitation of liability of directors

Our certificate of incorporation provides that no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:

• for any breach of the director’s duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of laws;

• for unlawful payment of a dividend or unlawful stock purchase or stock redemption; and

• for any transaction from which the director derived an improper personal benefit.

The effect of these provisions is to eliminate our rights and our stockholders’ rights, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for a breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.

88

Business Combination Under Delaware Law

We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.

Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:

• our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or

• the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 ²/3% of the outstanding voting stock that is not owned by the interested stockholder.

This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law. This election would be effective 12 months after the adoption of the amendment and would not apply to any business combination between us and any person who became an interested stockholder on or before the adoption of the amendment.

Registration rights

We intend to enter into a registration rights agreement with each of our three existing holders. Under the agreement, any one of the three existing holders may require us to file a registration statement under the Securities Act to register the sale of shares of our common stock, subject to certain limitations, including that the reasonably anticipated gross proceeds must be at least $15.0 million. These stockholders may request a total of six such registrations (two by the Mark A. Fischer 1994 Trust, two by the Susan L. Fischer 1994 Trust, and two by Altoma Energy G.P.) and only one in any six-month period. These holders also have the right to cause us to register their registrable securities on Form S-3, when it becomes available to us, if the reasonably anticipated

89

gross proceeds would be at least $10.0 million. In addition, if we propose to register securities under the Securities Act, then the holders who are party to the agreement will have “piggy-back” rights, subject to quantity limitations determined by underwriters if the offering involves an underwriting, to request that we register their registrable securities. There is no limit to the number of these “piggy-back” registrations in which these holders may request their shares be included. We generally will bear the registration expenses incurred in connection with registrations. We have agreed to indemnify these stockholders against certain liabilities, including liabilities under the Securities Act, in connection with any registration effected under the agreement. These registration rights will terminate at the earlier of (a) ten years from the closing date of this offering or (b) with respect to any holder, the date that all registrable securities held by that holder may be sold in a three-month period without registration under Rule 144 of the Securities Act and such registrable securities represent less than one-percent of all outstanding shares of our capital stock.

Transfer agent and registrar

The transfer agent and registrar for the common stock is                                                          .

Listing

We have applied to list our shares of common stock on the New York Stock Exchange under the symbol “CPR.”

90

Shares eligible for future sale

Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors also could make it more difficult to raise funds through future offerings of common stock.

After this offering,              shares of common stock will be outstanding. Of these shares, the              shares sold in this offering, or              shares if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. All of the shares outstanding other than the shares sold in this offering (a total of              shares, or              shares if the underwriters exercise their over-allotment option in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and subject to lock-up arrangements.

In connection with this offering, we and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements,              shares, or              shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144.

The restricted securities generally may not be sold unless they are registered under the Securities Act or are sold under an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. After this offering, the holders of              shares, or              shares if the underwriters exercise their over-allotment option in full, will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.

Our officers and directors and all of our stockholders will enter into lock-up agreements described in “Underwriting.”

As restrictions on resale end, the market price of our common stock could drop significantly if the holders of these restricted shares sell them, or are perceived by the market as intending to sell them.

91

Rule 144

In general, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least one year is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:

• 1% of the then outstanding shares of common stock; and

• the average weekly trading volume in the common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the Securities Exchange Commission.

Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.

Rule 144(k)

Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an “affiliate,” is entitled to sell the shares without complying with the manner of sale, public information, volume limitation or notice provision of Rule 144.

92

Material U.S. federal tax consequences

for non-U.S. holders of our common stock

The following is a general discussion of the material U.S. federal income and estate tax consequences to non-U.S. Holders with respect to the acquisition, ownership and disposition of our common stock. In general, a “Non-U.S. Holder” for purposes of this discussion is any beneficial owner of our common stock other than the following:

• an individual citizen or resident of the U.S., including an alien individual who is a lawful permanent resident of the U.S. or meets the “substantial presence” test under section 7701(b)(3) of the Internal Revenue Code of 1986, as amended (the “Code”);

• a corporation (or an entity treated as a corporation) created or organized in the U.S. or under the laws of the U.S., any state thereof, or the District of Columbia;

• a partnership (or an entity treated as a partnership);

• an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust, if a U.S. court can exercise primary supervision over the administration of the trust and one or more U.S. persons can control all substantial decisions of the trust, or certain other trusts that have a valid election to be treated as a U.S. person pursuant to the applicable Treasury Regulations.

This discussion is based on current provisions of the Code, final, temporary and proposed Treasury Regulations, judicial opinions, published positions of the Internal Revenue Service, or IRS, and all other applicable administrative and judicial authorities, all of which are subject to change, possibly with retroactive effect. This discussion does not address all aspects of U.S. federal income and estate taxation or any aspects of state, local, or non-U.S. taxation, nor does it consider any specific facts or circumstances that may apply to particular Non-U.S. Holders that may be subject to special treatment under the U.S. federal income tax laws including, but not limited to, insurance companies, real estate investment trusts, regulated investment companies, persons holding our common stock as part of a hedging or conversion transaction or a straddle or other risk-reduction transaction, tax-exempt organizations, pass-through entities, banks or financial institutions, brokers, dealers in securities, and U.S. expatriates. If a partnership or other entity treated as a partnership for U.S. federal income tax purposes is a beneficial owner of our common stock, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. This discussion assumes that the Non-U.S. Holder will hold our common stock as a capital asset, which generally is property held for investment.

Prospective investors are urged to consult their tax advisors regarding the U.S. federal, state and local, and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of common stock.

Dividends

In general, dividends paid to a Non-U.S. Holder (to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles) will be subject to U.S. withholding tax at a rate equal to 30% of the gross amount of the dividend, or a

93

lower rate prescribed by an applicable income tax treaty, unless the dividends are effectively connected with a trade or business carried on by the Non-U.S. Holder within the U.S. Under applicable Treasury regulations, a Non-U.S. Holder will be required to satisfy certain certification requirements, generally on IRS Form W-8BEN, or any successor form, directly or through an intermediary, in order to claim a reduced rate of withholding under an applicable income tax treaty. If tax is withheld in an amount in excess of the amount applicable under an income tax treaty, a refund of the excess amount may generally be obtained by filing an appropriate claim for refund with the IRS.

Dividends that are effectively connected with a U.S. trade or business (and, where an income tax treaty applies, are attributable to a U.S. permanent establishment of the Non-U.S. Holder) generally will not be subject to U.S. withholding tax if the Non-U.S. Holder files the properly completed required forms, including IRS Form W-8ECI, or any successor form, with the payor of the dividend, but instead generally will be subject to U.S. federal income tax on a net income basis in the same manner as if the Non-U.S. Holder were a resident of the U.S. A corporate Non-U.S. Holder that receives effectively connected dividends may be subject to an additional branch profits tax at a rate of 30%, or a lower rate prescribed by an applicable income tax treaty, on its “effectively connected earnings and profits,” subject to adjustments.

Gain on sale or other disposition of common stock

In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of the Non-U.S Holder’s shares of common stock unless:

• the gain is effectively connected with a trade or business carried on by the Non-U.S. Holder within the U.S. (and, where an income tax treaty applies, is attributable to a U.S. permanent establishment of the Non-U.S. Holder), in which case the branch profits tax discussed above may also apply if the Non-U.S. Holder is a corporation;

• the Non-U.S. Holder is an individual who holds shares of common stock as capital assets and is present in the U.S. for 183 days or more in the taxable year of disposition and certain other conditions are met; or

• we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes during specified periods.

A Non-U.S. Holder described in the first and third bullet points above will be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates. A Non-U.S. Holder described in the second bullet point above will be subject to a 30% tax on the gain derived from the sale, which may be offset by U.S. source capital losses.

Because of the oil and gas properties and other real property assets we own, we may be a “U.S. real property holding corporation.” The determination of whether we are a “U.S. real property holding corporation” is fact specific and depends on the composition of our assets. Generally, a corporation is a U.S. real property holding corporation if the fair market value of its U.S. real property interests, as defined in the Internal Revenue Code and applicable regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. If we are, have been, or become, a U.S.

94

real property holding corporation, and our common stock is regularly traded on an established securities market, a Non-U.S. Holder who (actually or constructively) holds or held (at anytime during the shorter of the five year period preceding the date of dispositions or the holder’s holding period) more than five percent of our common stock would be subject to U.S. federal income tax on a disposition of our common stock, but other Non-U.S. Holders generally would not be. If our common stock is not so traded, all Non-U.S. Holders would be subject to U.S. federal income tax on disposition of our common stock.

You are encouraged to consult your own tax advisor regarding our possible status as a “U.S. real property holding corporation” and its possible consequences in your particular circumstances.

Information reporting and backup withholding

Generally, we must report annually to the IRS the amount of dividends paid, the name and address of the recipient, and the amount, if any, of tax withheld. A similar report is sent to the recipient. These information reporting requirements apply even if withholding was not required because the dividends were effectively connected dividends or withholding was reduced by an applicable income tax treaty. Under income tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

Dividends paid to a Non-U.S. Holder that is not an exempt recipient generally will be subject to backup withholding, currently at a rate of 28% of the gross proceeds, unless a Non-U.S. Holder certifies as to its foreign status, which certification may be made on IRS Form W-8BEN.

Proceeds from the disposition of common stock by a Non-U.S. Holder effected by or through a U.S. office of a broker will be subject to information reporting and backup withholding, currently at a rate of 28% of the gross proceeds, unless the Non-U.S. Holder certifies to the payor under penalties of perjury as to, among other things, its address and status as a Non-U.S. Holder or otherwise establishes an exemption. Generally, U.S. information reporting and backup withholding will not apply to a payment of disposition proceeds if the transaction is effected outside the U.S. by or through a non-U.S. office. However, if the broker is, for U.S. federal income tax purposes, a U.S. person, a controlled foreign corporation, a foreign person who derives 50% or more of its gross income for specified periods from the conduct of a U.S. trade or business, specified U.S. branches of foreign banks or insurance companies or a foreign partnership with various connections to the U.S., information reporting, but not backup withholding, will apply unless:

• the broker has documentary evidence in its files that the holder is a Non-U.S Holder and certain other conditions are met; or

• the holder otherwise establishes an exemption.

Backup withholding is not an additional tax. Rather, the amount of tax withheld is applied as a credit to the U.S. federal income tax liability of persons subject to backup withholding. If backup withholding results in an overpayment of U.S. federal income taxes, a refund may be obtained, provided the required documents are timely filed with the IRS.

Estate tax

Our common stock owned or treated as owned by an individual who is not a citizen or resident of the U.S. (as specifically defined for U.S. federal estate tax purposes) at the time of death will be includible in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise.

95

Underwriting

J.P. Morgan Securities Inc. is acting as sole bookrunner, Banc of America Securities LLC and Lehman Brothers Inc. are acting as joint lead managers and Comerica Securities, Inc. and Fortis Securities LLC are acting as co-managers for this offering.

We and the underwriters named below have entered into an underwriting agreement covering the common stock to be sold in this offering. Each underwriter has severally agreed to purchase, and we and the selling stockholders have agreed to sell to each underwriter, the number of shares of common stock set forth opposite its name in the following table.

Name	Number of shares
J.P. Morgan Securities Inc.
Banc of America Securities LLC
Lehman Brothers Inc.
Comerica Securities, Inc.
Fortis Securities LLC
Total

The underwriting agreement provides that if the underwriters take any of the shares presented in the table above, then they must take all of the shares. No underwriter is obligated to take any shares allocated to a defaulting underwriter except under limited circumstances. The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions precedent, including the absence of any material adverse change in our business and the receipt of certain certificates, opinions and letters from us, our counsel and our independent auditors.

The underwriters are offering the shares of common stock, subject to the prior sale of shares, and when, as and if such shares are delivered to and accepted by them. The underwriters will initially offer to sell shares to the public at the initial public offering price shown on the front cover page of this prospectus. The underwriters may sell shares to securities dealers at a discount of up to $             per share from the initial public offering price. Any such securities dealers may resell shares to certain other brokers or dealers at a discount of up to $             per share from the initial public offering price. After the initial public offering, the underwriters may vary the public offering price and other selling terms.

If the underwriters sell more shares than the total number shown in the table above, the underwriters have the option to buy up to an additional              shares of common stock from us and              shares from the selling stockholders to cover such sales. They may exercise this option during the 30-day period from the date of this prospectus. If any shares are purchased with this option, the underwriters will purchase shares in approximately the same proportion as shown in the table above. If any additional shares of common stock are purchased, the underwriters will offer the additional shares on the same terms as those on which the shares are being offered.

At our request, the underwriters have reserved up to 5% of the total underwritten shares offered by this prospectus as part of our Directed Share Program. These shares will be offered at the initial public offering price to certain of our officers, directors, employees and certain other persons associated with us. The number of shares available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares not so

96

purchased will be offered by the underwriters to the general public on the same basis as the other shares offered hereby. The Directed Share Program will be arranged through one of our underwriters, Lehman Brothers.

The following table shows the per share and total underwriting discounts that we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

	Paid by the Company		Paid by selling stockholders
	Without option exercise	With full option exercise	Without option exercise	With full option exercise
Per share	$	$	$	$
Total	$	$	$	$

The underwriters have advised us that they may make short sales of our common stock in connection with this offering, resulting in the sale by the underwriters of a greater number of shares than they are required to purchase pursuant to the underwriting agreement. The short position resulting from those short sales will be deemed a “covered” short position to the extent that it does not exceed the shares subject to the underwriters’ overallotment option and will be deemed a “naked” short position to the extent that it exceeds that number. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the trading price of the common stock in the open market that could adversely affect investors who purchase shares in this offering. The underwriters may reduce or close out their covered short position either by exercising the overallotment option or by purchasing shares in the open market. In determining which of these alternatives to pursue, the underwriters will consider the price at which shares are available for purchase in the open market as compared to the price at which they may purchase shares through the overallotment option. Any “naked” short position will be closed out by purchasing shares in the open market. Similar to the other stabilizing transactions described below, open market purchases made by the underwriters to cover all or a portion of their short position may have the effect of preventing or retarding a decline in the market price of our common stock following this offering. As a result, our common stock may trade at a price that is higher than the price that otherwise might prevail in the open market.

The underwriters have advised us that, pursuant to Regulation M under the Securities Act, they may engage in transactions, including stabilizing bids or the imposition of penalty bids, that may have the effect of stabilizing or maintaining the market price of the shares of common stock at a level above that which might otherwise prevail in the open market. A “stabilizing bid” is a bid for or the purchase of shares of common stock on behalf of the underwriters for the purpose of fixing or maintaining the price of the common stock. A “penalty bid” is an arrangement permitting the underwriters to claim the selling concession otherwise accruing to an underwriter or syndicate member in connection with the offering if the common stock originally sold by that underwriter or syndicate member is purchased by the underwriters in the open market pursuant to a stabilizing bid or to cover all or part of a syndicate short position. The underwriters have advised us that stabilizing bids and open market purchases may be effected on the NYSE, in the over-the-counter market or otherwise and, if commenced, may be discontinued at any time.

One or more of the underwriters may facilitate the marketing of this offering online directly or through one of its affiliates. In those cases, prospective investors may view offering terms and a

97

prospectus online and, depending upon the particular underwriter, place orders online or through their financial advisor.

We estimate that our share of the total expenses of this offering, excluding underwriting discounts, will be approximately $2,000,000.

We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act.

We and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. Notwithstanding the foregoing, our executive officers, directors and stockholders may transfer shares of common stock or common stock equivalents (1) as a bona fide gift or gifts without consideration, (2) to any trust for the direct or indirect benefit of such person or the immediate family member of such person, (3) to any “affiliate” of such stockholder, or (4) to any partner or beneficiary of such current stockholder as a distribution or upon the dissolution of such stockholder, provided in each case the donee or assignee thereof agrees to be bound in writing by the foregoing lock-up restrictions. In addition, we may issue shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock (1) for the benefit of our employees, directors and officers under benefit plans described in this prospectus or (2) in connection with any acquisitions in an aggregate amount not to exceed 10% of the number of our issued and outstanding shares of common stock on the closing date of this offering, provided that the recipient of any such shares agrees to be bound by the foregoing lock-up restrictions.

The underwriters have informed us that they will not confirm sales to accounts over which they exercise discretionary authority without prior written approval of the customer.

We have applied to list our common stock on the NYSE under the symbol “CPR.” The underwriters intend to sell shares of our common stock to a minimum of 2,000 beneficial owners in lots of 100 or more so as to meet the distribution requirements of this listing.

There has been no public market for the common stock prior to this offering. We, the selling stockholders and the underwriters will negotiate the initial public offering price. In determining the initial public offering price, we, the selling stockholders and the underwriters expect to consider a number of factors in addition to prevailing market conditions, including:

• the history of and prospects for our industry;

• an assessment of our management;

• our present operations;

• our historical results of operations;

• the trend of our revenues and earnings; and

• our earnings prospects.

We, the selling stockholders and the underwriters will consider these and other relevant factors in relation to the price of similar securities of generally comparable companies. None of the Company, the selling stockholders and the underwriters can assure investors that an active

98

trading market will develop for the common stock, or that the common stock will trade in the public market at or above the initial public offering price.

JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. The amount of outstanding indebtedness owed to such lender affiliates under our Credit Agreement will be reduced with a portion of the net proceeds from this offering, which may result in these underwriters being deemed to have received more than 10% of the net offering proceeds. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2720 of the Conduct Rules. Rule 2720 requires that the initial public offering price can be no higher than that recommended by a “qualified independent underwriter,” as defined by the NASD. Accordingly, Lehman Brothers Inc., another underwriter of this offering, is assuming the responsibilities of acting as the qualified independent underwriter in pricing this offering, conducting due diligence and reviewing and participating in the preparation of this prospectus and the registration statement of which this prospectus forms a part. The initial public offering price of the shares of common stock will be no higher than the price recommended by Lehman Brothers Inc.

From time to time in the ordinary course of their respective businesses, certain of the underwriters and their affiliates perform various financial advisory, investment banking and commercial banking services from time to time for us and our affiliates. For example, J.P. Morgan Chase Bank, an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. We intend to repay $             million of the amounts outstanding under our Credit Agreement with a portion of the net proceeds of this offering, of which approximately $             million will reduce the indebtedness outstanding to such affiliates in the aggregate. See “Use of proceeds.”

99

Legal matters

The validity of our shares of common stock offered by this prospectus will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Legal matters in connection with this offering will be passed upon for the underwriters by Cahill Gordon & Reindel LLP, New York, New York.

Experts

The consolidated financial statements of Chaparral Energy Inc. and subsidiaries (formerly Chaparral, L.L.C. and subsidiaries) as of December 31, 2003 and 2004 and for each of the three years in the period ended December 31, 2004 and the financial statements of CEI Bristol Acquisition, L.P. as of December 31, 2003 and 2004 and for each of the three years in the period ended December 31, 2004, included in this prospectus and registration statement, have been audited by Grant Thornton LLP, independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

Reserve engineers

Certain estimates of our net oil and natural gas reserves and related information as of December 31, 2003 and 2002 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. Certain estimates of our net proved oil and natural gas reserves and the net proved oil and natural gas reserves of CEI Bristol as of December 31, 2004 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc. All such information has been so included on the authority of such firms as experts regarding the matters contained in their reports.

Where you can find more information

We have filed with the SEC a registration statement on Form S-1, including exhibits and schedules, under the Securities Act with respect to the common stock to be sold in this offering. 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 our common stock, 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

100

reference rooms. Our filings, including the registration statement, will also be available to you on the Internet web site maintained by the SEC at http://www.sec.gov.

Following the completion of this offering, 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.

101

Glossary of terms

The terms defined in this section are used throughout this prospectus:

Bbl	One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
Bcf	One billion cubic feet of natural gas.
Bcfe	One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.
Btu	British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Basin	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Fully developed F&D cost	Total capital costs, including future development costs, related to acquisition, exploration and development activities divided by total proved reserve acquisitions, extensions, 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.

A-1

MMcfe	One million cubic feet of natural gas equivalents.
NYMEX	The New York Mercantile Exchange.
Net acres	The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
Net working interest	A working interest owner’s gross working interest in production, less the related royalty, overriding royalty, production payment, and net profits interests.
PDP	Proved developed producing.
PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.
Primary recovery	The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.
Proved developed reserves	Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves	The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Proved undeveloped reserves	Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Sand	A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.
Secondary recovery	The recovery of oil and gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.

A-2

Seismic survey	Also known as a seismograph survey, is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
Tertiary recovery	The use of any improved recovery method, including injection of CO2, to remove additional oil after secondary recovery. Compare primary recovery, secondary recovery.
Unit	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
WTI Cushing spot price	The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.
Waterflood	The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.
Wellbore	The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.
Working interest	The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Zone	A layer of rock which has distinct characteristics that differ from nearby rock.

A-3

Index to financial statements

	Page
Chaparral Energy, Inc. historical consolidated financial statements:
Report of independent registered public accounting firm	F1-1
Consolidated balance sheets as of December 31, 2003 and 2004 and September 30, 2005 (unaudited)	F1-2
Consolidated statements of income for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F1-3
Consolidated statements of members’/stockholders’ equity (deficit) and comprehensive income (loss) for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2005 (unaudited)	F1-4
Consolidated statements of cash flows for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F1-5
Notes to consolidated financial statements	F1-7
CEI Bristol historical financial statements:
Report of independent registered public accounting firm	F2-1
Balance sheets as of December 31, 2003 and 2004 and September 30, 2005 (unaudited)	F2-2
Statements of operations for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F2-3
Statement of partners’ capital for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2005 (unaudited)	F2-4
Statements of cash flows for the years ended December 31, 2002, 2003 and 2004 and the nine months ended September 30, 2004 and 2005 (unaudited)	F2-5
Notes to financial statements	F2-7

F-1

Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. (a Delaware corporation, formerly Chaparral, L.L.C.) and Subsidiaries as of December 31, 2003 and 2004, and the related consolidated statements of income, members’/stockholders’ equity (deficit) and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2004. 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, 2003 and 2004, and the results of their operations and their 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 consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

GRANT THORNTON LLP

Oklahoma City, Oklahoma

April 1, 2005

F1-1

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Consolidated balance sheets

	December 31,						September 30,
(dollars in thousands except, shares and per share amounts)	2003			2004			2005
							(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	5,052		$	13,842		$	51,057
Accounts receivable, net		22,995			26,357			43,824
Accounts receivable from related party		5,332			1,444			—
Inventories		2,111			3,596			3,752
Deferred income taxes		3,226			5,772			33,362
Prepaid expenses		1,165			1,488			1,495
Total current assets		39,881			52,499			133,490
Property and equipment—at cost, net		16,700			19,920			21,935
Oil & gas properties, using the full cost method:
Proven oil & gas properties		184,667			274,466			534,067
Unproven oil & gas properties (excluded from amortization)		2,180			4,982			8,583
Accumulated depreciation, depletion and amortization		(33,087	)		(48,384	)		(68,624	)
Oil & gas properties, net		153,760			231,064			474,026
Other assets		745			4,643			3,103
	$	211,086		$	308,126		$	632,554
Liabilities and members’/stockholders’ equity (deficit)
Current liabilities:
Accounts payable and accrued liabilities	$	20,935		$	25,985		$	38,818
Revenue distribution payable and other current liabilities		13,793			13,794			15,281
Well deposits		188			1,437			1,125
Current maturities of long-term debt and capital leases		1,417			2,159			134,946
Current maturities of notes payable to members		1,000			—			—
Short-term derivative instruments		7,025			13,810			136,603
Total current liabilities		44,358			57,185			326,773
Long-term debt and capital leases, less current maturities		115,907			174,463			253,283
Notes payable to members, less current maturities		31			—			—
Hedge instruments		1,620			7,425			40,742
Deferred compensation		—			120			345
Asset retirement obligations		7,566			10,062			14,138
Deferred income taxes		15,526			22,735			17,155
Commitments and contingencies (Note 13)
Members’/stockholders’ equity (deficit):
Members’ units/common stock, 50,000,000 units issued outstanding as of December 31, 2003 and 2004; common stock, $.01 par value—5,000 shares authorized; 1,000 shares issued and outstanding as of September 30, 2005		1			1			1
Undistributed/retained earnings		30,977			48,242			55,147
Accumulated other comprehensive loss, net of taxes		(4,900	)		(12,107	)		(75,030	)
		26,078			36,136			(19,882	)
	$	211,086		$	308,126		$	632,554

The accompanying notes are an integral part of these statements.

F1-2

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Consolidated statements of income

	Year ended December 31,									Nine months ended September 30,
(dollars in thousands, except share and per share amounts)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Revenues:
Oil and gas sales	$	42,653		$	74,186		$	113,546		$	76,504		$	130,727
Loss from oil and gas hedging activities		(749	)		(12,220	)		(21,350	)		(14,073	)		(39,743	)
Total revenues		41,904			61,966			92,196			62,431			90,984
Costs and expenses:
Lease operating		14,506			18,706			25,392			18,342			25,765
Production tax and gas handling charges		3,645			5,654			9,808			6,537			12,075
Depreciation, depletion and amortization		7,910			10,376			18,234			11,559			23,089
General and administrative		4,059			4,946			5,985			4,473			6,631
Total costs and expenses		30,120			39,682			59,419			40,911			67,560
Operating income		11,784			22,284			32,777			21,520			23,424
Non-operating income (expense):
Interest expense		(3,998	)		(4,116	)		(6,162	)		(4,099	)		(8,283	)
Other income		1,012			208			279			336			524
Net non-operating expense		(2,986	)		(3,908	)		(5,883	)		(3,763	)		(7,759	)
Income from continuing operations before income taxes and accounting change		8,798			18,376			26,894			17,757			15,665
Income tax expense		3,134			6,932			9,629			6,358			5,701
Income from continuing operations before accounting change		5,664			11,444			17,265			11,399			9,964
Cumulative effect of change in accounting principle, less applicable income tax benefit of $537		—			(887	)		—			—			—
Discontinued operations, less applicable income tax benefit of $323		(617	)		—			—			—			—
Net income	$	5,047		$	10,557		$	17,265		$	11,399		$	9,964
Earnings per share (historical):
Income per share from continuing operations	$	5,664		$	11,444		$	17,265		$	11,399		$	9,964
Income (loss) per share from accounting change, net		—			(887	)		—			—			—
Income (loss) per share from discontinued operations, net		(617	)		—			—			—			—
Net Income per share	$	5,047		$	10,557		$	17,265		$	11,399		$	9,964
Weighted average number of shares used in calculation of basic and diluted earnings per share		1,000			1,000			1,000			1,000			1,000
Earnings per share (pro forma for stock split):
Income per share from continuing operations	$			$			$			$			$
Income (loss) per share from accounting change, net
Income (loss) per share from discontinued operations, net
Net Income per share	$			$			$			$			$
Weighted average number of shares used in calculation of basic and diluted earnings per share

The accompanying notes are an integral part of these statements.

F1-3

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Consolidated statements of members’/

stockholders’ equity (deficit) and comprehensive

income (loss)

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

	Members’ units/ Common Stock				Accumulated other comprehensive income (loss)			Undistributed/ Retained earnings			Total
(dollars in thousands)	Units/Shares		Amount
Balance at January 1, 2002	50,000,000		$	1	$	3,379		$	15,373		$	18,753
Net income	—			—		—			5,047			5,047
Other comprehensive loss, net
Unrealized loss on hedges, net of taxes of $4,362	—			—		(7,205	)		—			(7,205	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $51	—			—		93			—			93
Total comprehensive loss												(2,065	)
Balance at December 31, 2002	50,000,000			1		(3,733	)		20,420			16,688
Net income	—			—		—			10,557			10,557
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $5,193	—			—		(8,530	)		—			(8,530	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $4,437	—			—		7,363			—			7,363
Total comprehensive income												9,390
Balance at December 31, 2003	50,000,000			1		(4,900	)		30,977			26,078
Net income	—			—		—			17,265			17,265
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $12,766	—			—		(20,152	)		—			(20,152	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $7,801	—			—		12,945			—			12,945
Total comprehensive income												10,058
Balance at December 31, 2004	50,000,000			1		(12,107	)		48,242			36,136
Conversion from LLC to C Corporation	(49,999,000	)		—		—			—			—
Distributions to members (unaudited)	—			—		—			(3,059	)		(3,059	)
Net income (unaudited)	—			—		—			9,964			9,964
Other comprehensive loss, net (unaudited)
Unrealized loss on hedges, net of taxes of $50,022	—			—		(80,148	)		—			(80,148	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $10,838	—			—		17,225			—			17,225
Total comprehensive loss												(52,959	)
Balance at September 30, 2005 (unaudited)	1,000		$	1	$	(75,030	)	$	55,147		$	(19,882	)

The accompanying notes are an integral part of this statement.

F1-4

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Consolidated statements of cash flows

	Year ended December 31,									Nine months ended September 30,
(dollars in thousands)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Cash flows from operating activities
Net income	$	5,047		$	10,557		$	17,265		$	11,399		$	9,964
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		7,910			10,376			18,234			11,559			23,089
Cumulative effect of accounting change		—			1,424			—			—			—
Loss on discontinued operations		940			—			—			—			—
Deferred income taxes		2,995			6,959			9,442			6,352			6,014
Unrealized loss on ineffective portion of hedges		605			420			604			1,596			11,680
(Gain) Loss on sale of assets		113			23			97			(63	)		(226	)
Partnership (income) loss		81			(45	)		(173	)		(147	)		92
Accrued interest expense added to principal		178			99			27			27			—
Bad debt expense		260			359			248			220			94
Change in assets & liabilities, net of assets and liabilities of business acquired
(Increase) Decrease in accounts receivable		2,287			(15,184	)		278			1,707			(10,250	)
(Increase) Decrease in inventories		191			(344	)		(1,402	)		(1,965	)		(156	)
(Increase) Decrease in prepaid expenses and other assets		337			(14	)		(834	)		(300	)		(121	)
Increase (Decrease) in accounts payable and accrued liabilities		(4,058	)		8,899			4,694			3,194			8,750
Increase (Decrease) in revenue distribution payable and other current liabilities		1,249			9,098			1			1,153			1,487
Increase in deferred compensation		—			—			120			90			225
Increase (Decrease) in well deposits		(655	)		(86	)		1,248			1,463			198
Net cash provided by operating activities		17,480			32,541			49,849			36,285			50,840
Cash flows from investing activities
Partnership investment		(31	)		(40	)		(72	)		(30	)		(33	)
Partnership distribution		—			53			152			119			63
Purchase of property and equipment and oil and gas properties		(40,683	)		(56,652	)		(97,926	)		(69,711	)		(109,398	)
Acquisition of a business, net of cash acquired		—			—			—			—			(113,622	)
Proceeds from dispositions of property and equipment and oil and gas properties		13,209			1,426			2,726			1,278			981
Net cash used in investing activities		(27,505	)		(55,213	)		(95,120	)		(68,344	)		(222,009	)
Cash flows from financing activities
Proceeds from long-term debt		19,398			28,491			58,358			40,870			81,736
Repayment of long-term debt		(8,998	)		(583	)		(2,431	)		(845	)		(1,797	)
Proceeds from acquisition financing		—			—			—			—			132,000
Principal payments under capital lease obligations		(961	)		(744	)		(807	)		(715	)		(402	)
Repayments of notes payable to members		(518	)		(1,018	)		(1,059	)		(1,054	)		—
Distributions to members		—			—			—			—			(3,059	)
Fees paid related to financing activities		—			—			—			—			(94	)
Net cash provided by financing activities		8,921			26,146			54,061			38,256			208,384
Net cash provided by discontinued operations		445			—			—			—			—
Net increase (decrease) in cash and cash equivalents		(659	)		3,474			8,790			6,197			37,215
Cash and cash equivalents at beginning of year		2,237			1,578			5,052			5,052			13,842
Cash and cash equivalents at end of year	$	1,578		$	5,052		$	13,842		$	11,249		$	51,057

The accompanying notes are an integral part of these statements.

F1-5

	Year ended December 31,						Nine months ended September 30,
(dollars in thousands)	2002		2003		2004		2004		2005
							(unaudited)		(unaudited)
Supplemental cash flow information
Cash paid during the year for:
Interest, net of capitalized interest	$	4,243	$	3,898	$	5,524	$	3,719	$	7,958
Income taxes		17		—		17		5		35

Supplemental disclosure of noncash investing and financing activities

(dollars in thousands)

During the year ended December 31, 2004 and the nine months ended September 30, 2005, the Company recorded an asset and related liability of $775 and $2,576, respectively associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties. (See “Asset Retirement Obligations” section of Note 1). No such amounts were recorded during the nine months ended September 30, 2004.

During the year ended December 31, 2002, the Company entered into capital lease obligations of $1,592 for the purchase of computer software. During the year ended December 31, 2003, the Company entered into capital lease obligations of $330 for the purchase of lease and well equipment. During the year ended December 31, 2004, the Company entered into capital leases for the purchase of machinery and equipment of $82 and purchased two licenses for seismic data by incurring long-term obligations of $4,096. During the nine months ended September 30, 2005, the Company entered into capital lease obligations of $70 for the purchase of machinery and equipment. No capital leases were entered into during the nine months ended September 30, 2004.

Effective on January 1, 2003, the Company recorded the cumulative effect of SFAS No. 143 for asset retirement obligations, as follows:

Increase in oil and gas properties	$	4,437
Increase in asset retirement obligations		(5,861	)
Cumulative effect of accounting change	$	(1,424	)

The accompanying notes are an integral part of these statements.

F1-6

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements

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

(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of accounting policies

Chaparral Energy, Inc. and its wholly owned subsidiaries, formerly Chaparral, L.L.C. and Subsidiaries, (collectively, the “Company”) is involved in the acquisition, exploration, development, production and operation of oil and gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas and Wyoming.

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

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

Interim financial statements

The financial information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the nine month period ended September 30, 2005 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2005.

Principles of consolidation

The consolidated financial statements include the accounts of the Company. All significant intercompany balances and transactions have been eliminated.

Use of estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management makes estimates based on knowledge and experience; accordingly, actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, deferred income taxes, asset retirement obligations and others, and are subject to change.

Cash and cash equivalents

The Company maintains cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Company has not experienced any losses in such

F1-7

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

accounts and believes it is not exposed to any significant credit risk on such accounts. At December 31, 2003 and 2004, the Company has cash and cash equivalents of $4,426 and $11,654, respectively, at one financial institution, from which the Company also has significant borrowings. Cash and cash equivalents at financial institutions from which the Company also has significant borrowings totaled $49,565 as of September 30, 2005.

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

Accounts receivable

The Company has receivables from joint interest owners and oil and gas purchasers which are generally uncollateralized. The Company generally reviews these parties for credit worthiness and general financial condition. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Accounts receivable past due 90 days or more and still accruing interest at December 31, 2003 and 2004 were $2,238 and $1,237, 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, 2002, 2003, and 2004 was $260, $359, and $248, respectively. Interest accrues beginning on the day after the due date of the receivable. All interest previously accrued but not collected is reversed against current interest income when the account is determined to be uncollectible. Accounts receivable consisted of the following at December 31:

	2003			2004
Joint interests	$	18,077		$	13,089
Accrued oil and gas sales		8,315			13,651
Other		2,035			1,261
Allowance for doubtful accounts		(100	)		(200	)
	$	28,327		$	27,801

Inventories

Inventories consist of equipment used in developing oil and gas properties of $1,313 and $2,664 at December 31, 2003 and 2004, respectively, and oil in tank batteries of $798 and $932 at December 31, 2003 and 2004, respectively. Inventories consist of equipment used in developing oil and gas properties of $2,690 and oil in tank batteries of $1,062 at September 30, 2005.

F1-8

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Equipment inventory is carried at the lower of cost or market using the specific identification method. Crude oil inventories are stated at the lower of production cost or market.

Property and equipment

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

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives are as follows:

Furniture and fixtures	10 years
Automobiles and trucks	5 years
Machinery and equipment	10 - 20 years
Office and computer equipment	5 - 10 years
Building and improvements	10 - 40 years

Oil and gas properties

The Company uses the full-cost method of accounting for oil and gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the exploration for and development of oil and gas reserves. Proceeds from disposition of oil and gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries, benefits and other internal costs directly attributable to these activities.

Depreciation, depletion and amortization of oil and gas properties are provided using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. Depreciation, depletion and amortization expense of oil and gas properties was $6,463, $8,144, and $15,297 for the years ended December 31, 2002, 2003, and 2004 respectively. Depreciation, depletion and amortization expense of oil and gas properties was $9,504 and $20,241 for the nine months ended September 30, 2004 and 2005, respectively.

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling

F1-9

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

test and depletion of oil and gas properties should be calculated in accordance with the provisions of SFAS No. 143. The Company adopted SAB No. 106 prospectively in the fourth quarter of 2004. However, this adoption did not materially impact the full cost ceiling test calculation or depletion for 2004.

In accordance with the full-cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for the Company’s cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Investment in partnerships

The Company has a 1% general partner’s interest in an oil and gas limited partnership, CEI Bristol Acquisition, L.P. (“CEI Bristol”). Once the limited partner has received cash distributions in the amount of capital contributions, plus amounts to yield an annual rate of return of 11%, as defined in the agreement, the general partner will receive an additional 34% of revenues and expenses. Because of the general partner’s ability to influence the operations, the Company’s investment in CEI Bristol is accounted for under the equity method. The investment is included in other assets and was $648 and $741 as of December 31, 2003 and 2004, respectively.

On September 30, 2005 the Company acquired the 99% limited partner interest in CEI Bristol Acquisition, L.P. and as a result CEI Bristol became a wholly owned subsidiary of the Company as of September 30, 2005.

Well deposits

Well deposits consist of amounts received from other interest owners for intangible drilling and tangible equipment expenditures which were authorized in advance of the actual expenditures.

Deferred income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. The Company records a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

F1-10

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Revenue recognition

Oil revenue is recognized when the product is delivered to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Company recognizes gas imbalances on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for the Company’s obligation for natural gas taken by its purchasers which exceeds the Company’s ownership interest of the well’s total production. The Company’s aggregate imbalance due to over production is approximately 1,336,000 thousand cubic feet (mcf) of gas and 1,027,000 mcf at December 31, 2003 and 2004, respectively. The Company’s aggregate imbalance due to under production is approximately 1,919,000 mcf and 1,508,000 mcf at December 31, 2003 and 2004, respectively.

Hedge transactions

The Company uses price swaps and collars to reduce the effect of fluctuations in crude oil and natural gas 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.

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.

F1-11

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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 2002, 2003 or 2004. The ineffective portion of derivative gains or losses is reported as loss from oil and gas hedging activities on the consolidated statements of income.

Asset retirement obligations

On January 1, 2003, the Company adopted SFAS No. 143 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 Company recorded a net asset of $4,437, a related liability of $5,861 (using an 8.5% discount rate) and a cumulative loss effect of accounting change of $887, net of tax benefit of $537. The pro forma balance of the asset retirement obligation at January 1, 2002 and 2003 would have been $4,581 and $5,861, respectively, and pro forma net income would have been $4,743 and $11,444 for the years ended December 31, 2002 and 2003, respectively.

The activity incurred in the asset retirement obligation since adoption is as follows:

	As of December 31,						As of September 30,
	2003			2004			2005
Beginning balance	$	—		$	7,816		$	10,324
Adoption of SFAS No. 143		5,861			—			—
Liabilities incurred in current period		1,777			775			635
Liabilities acquired (see Note 2)		—			—			2,021
Liabilities settled in current period		(375	)		(375	)		(163	)
Accretion expense		553			768			762
Revisions of estimated cash flows		—			1,340			1,941
Ending ARO balance		7,816			10,324			15,520
Less current portion		250			262			1,382
	$	7,566		$	10,062		$	14,138

F1-12

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Environmental liabilities

Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2004 and 2003, the Company has not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon capital expenditures, operating results or the competitive position of the Company.

Recently issued accounting standards

In December, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), Share-Based Payment. SFAS No. 123(R) amends SFAS No. 123, Accounting for Stock-Based Compensation, and APB Opinion 25, Accounting for Stock Issued to Employees. SFAS No. 123(R) requires that the cost of share-based payment transactions (including those with employees and nonemployees) be recognized in the financial statements. SFAS No. 123(R) applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options or other equity instruments (except for those held by an ESOP) or by incurring liabilities (1) in amounts based (even in part) on the price of the entity’s shares or other equity instruments or (2) that require (or may require) settlement by the issuance of an entity’s share or other equity instruments. We will adopt SFAS 123R as of the first interim period beginning January 1, 2006. We are currently in the process of assessing the impact of adopting this new standard.

In EITF 04-5 the Emerging Issues Task Force (“EITF”) has reached consensus, subject to ratification by the Financial Accounting Standards Board (“FASB”), regarding when a limited partnership should be consolidated by its general partner. The proposed framework presumes that a sole general partner in a limited partnership controls the limited partnership. The presumption of control can be overcome if the limited partners have (i) the substantive ability to remove the sole general partner or otherwise dissolve the limited partnership or (ii) substantive participating rights. The EITF has concluded that a general partner lacks control if the limited partners can remove the general partner with a simple majority vote. The Company is currently evaluating what impact, if any, that EITF 04-5 will have. The consensus would be effective in the first reporting period in 2006.

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

F1-13

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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.

Earnings per share

The Company computes earnings per share under the provisions of SFAS No. 128, Earnings per Share, whereby 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, unless the effect of such increase would be anti-dilutive. There were no potentially dilutive securities outstanding during the periods presented.

In September 2005, Chaparral Energy, Inc. was incorporated in the state of Delaware. At the effective time of the reincorporation, all member units of Chaparral Energy, L.L.C were converted to 1,000 shares of Chaparral Energy, Inc. common stock. For purposes of calculating earnings per share, the recapitalization has been retroactively reflected for all periods presented in the accompanying consolidated statements of operations.

F1-14

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

The computations of basic and diluted earnings per share for the years ended December 31, 2002, 2003, and 2004 and the nine months ended September 30, 2004 and 2005 are as follows:

	Year ended December 31,								Nine months ended September 30,
(dollars in thousands, except share and per share amounts)	2002			2003			2004		2004		2005
									(unaudited)		(unaudited)
Numerator for basic and diluted earnings per share:
Income from continuing operations	$	5,664		$	11,444		$	17,265	$	11,399	$	9,964
Cumulative effect of a change in accounting principle, net		—			(887	)		—		—		—
Income (loss) from discontinued operations		(617	)		—			—		—		—
Earnings on common stock	$	5,047		$	10,557		$	17,265	$	11,399	$	9,964
Denominator for basic and diluted earnings per share:
Weighted average number of common shares		1,000			1,000			1,000		1,000		1,000
Basic and diluted earnings per share:
Continuing operations	$	5,664		$	11,444		$	17,265	$	11,399	$	9,964
Accounting change		—			(887	)		—		—		—
Discontinued operations		(617	)		—			—		—		—
Total basic and diluted income per share	$	5,047		$	10,557		$	17,265	$	11,399	$	9,964

Reclassifications

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

Note 2. Acquisition of CEI Bristol Acquisition, L.P. (unaudited)

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.

F1-15

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Total consideration paid by the Company was approximately $158,108, subject to certain purchase price adjustments. Prior to the acquisition, the Company held a 1% general partner interest through our wholly-owned subsidiary Chaparral Oil, L.L.C. and TIFD III-X LLC held a 99% limited partner interest in CEI Bristol. As a result of the acquisition, CEI Bristol became one of the Company’s wholly-owned subsidiaries. The acquisition cost was funded with proceeds from a bridge loan facility with General Electric Capital Corporation, borrowings from the Company’s revolving line of credit and cash on hand. Hedge liabilities of $42,108 were not designated as hedges were settled on October 3, 2005.

The acquisition was accounted for using the purchase method in accordance with the provisions of SFAS No. 141, Business Combinations. The estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition are as follows:

Oil and gas properties	$	154,326
Other current assets, including cash of $44,486		52,207
Accounts payable and accrued expenses		(4,296	)
Hedge liabilities		(42,108	)
Asset retirement obligations		(2,021	)
Net assets acquired	$	158,108

The unaudited pro forma information of the Company set forth below includes the operations of Chaparral and CEI Bristol for the year ended December 31, 2004 and nine months ended September 30, 2005 as if the acquisition occurred on January 1, 2004. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

	Year ended December 31, 2004				Nine months ended September 30, 2005
	As reported		Pro forma		As reported		Pro forma
Revenue	$	92,196	$	125,614	$	90,984	$	107,921
Net income	$	17,265	$	20,305	$	9,964	$	7,470

F1-16

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 3: Property and equipment

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

	2003		2004
Furniture and fixtures	$	414	$	885
Automobiles and trucks		3,629		4,164
Machinery and equipment		4,965		6,165
Office and computer equipment		3,355		3,645
Building and improvements		2,820		10,860
		15,183		25,719
Less accumulated depreciation and amortization		5,289		6,619
		9,894		19,100
Land		734		820
Construction in progress		6,072		—
	$	16,700	$	19,920

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

	2003		2004
Automobiles and trucks	$	684	$	—
Office and computer equipment		1,760		1,702
Machinery and equipment		—		82
		2,444		1,784
Less accumulated depreciation and amortization		564		676
	$	1,880	$	1,108

Note 4: Hedge activities and financial instruments

Hedge activities

The results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of this exposure, the Company has entered into derivative contracts designated as cash flow hedges. All derivative instruments have been entered into and designated as hedges of oil and gas price risk and not for speculative or trading purposes. As of December 31, 2004, the Company’s derivative instruments were comprised of oil and gas swaps. For swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price

F1-17

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. The Company pays the counterparty the excess of the commodity market price over the fixed price and will receive the excess of the fixed price over the market price, as defined in each instrument. The estimated fair values of derivative instruments as of December 31, 2003 were liabilities of $4,185 and $4,460 for gas swaps and oil swaps, respectively. The estimated fair values of derivative instruments as of December 31, 2004 were liabilities of approximately $5,152 and $16,083 for gas swaps and oil 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. The actual effect on future results of operations will be based on the market prices at the time of settlement and may be more or less than fair value estimates used at the balance sheet date.

Hedge loss is reported in loss from oil and gas hedging activities in the consolidated statements of income and is comprised of the following:

	Year ended December 31,						Nine months ended September 30,
	2002		2003		2004		2004		2005
Reclassification of settled contracts	$	144	$	11,800	$	20,746	$	12,477	$	28,063
Loss on ineffective portion of derivatives qualifying for hedge accounting		605		420		604		1,596		11,680
	$	749	$	12,220	$	21,350	$	14,073	$	39,743

Based upon the market prices at September 30, 2005, the Company expects to charge to income $52,354 of the balance in accumulated other comprehensive loss during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of September 30, 2005 are expected to be settled by June 2008. Short-term derivative instruments liability as of September 30, 2005 in the accompanying consolidated balance sheet includes $42,108 related to derivatives of CEI Bristol, which as of the September 30, 2005 acquisition were not designated as hedges, and were extinguished at the carrying amount on October 3, 2005.

Fair value of financial instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2003 and 2004 approximates fair value because substantially all debt carries variable market rates.

Fair value amounts have been estimated using available market information and valuation methodologies. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

F1-18

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Concentration of credit risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of hedge instruments and accounts receivable. Hedge instruments are exposed to credit risk from counterparties. Counterparties to the Company’s hedge instruments are primarily affiliates of its lenders and, therefore, the Company believes the counterparty risk is not significant. Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties the Company operates. The industry concentration has the potential to impact the Company’s overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

F1-19

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 5: Long-term debt

Long-term debt consists of the following:

	December 31,				September 30,
	2003		2004		2005
Revolving credit line with banks(1)	$	109,289	$	164,389	$	243,500
Short-term note, payable in lump sum payment of principal and interest due June 30, 2006, bearing interest at LIBOR plus 2% (effective rate of 5.92% at September 30, 2005); collateralized by the oil and gas properties of CEI Bristol Acquisition, L.P.		—		—		132,000
Real estate mortgage note, payable in monthly installments of $53, bearing interest at the national prime rate plus 0.25% adjusted annually (effective rate of 5.00% at December 31, 2004 and September 30, 2005), due August 31, 2010; collateralized by real property(2)		5,296		6,549		6,301
Real estate mortgage note, payable in monthly installments of $3, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2004 and September 30, 2005), adjusted and fixed every five years with a floor rate of 7%, due January 11, 2017; collateralized by real property		285		267		255
Real estate mortgage note, payable in monthly installments of $1, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2004 and September 30, 2005), adjusted and fixed every five years with a floor rate of 7%, due May 15, 2017; collateralized by real property		88		84		81
Real estate mortgage note, payable in monthly installments of $2, bearing interest at 4.75%, due May 1, 2019; collateralized by real property		—		254		245
Real estate mortgage note, interest only monthly payments beginning August 5, 2005 at 6.04% with lump sum principal payment due at maturity, July 5, 2006; collateralized by real property		—		—		252

F1-20

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

	December 31,				September 30,
	2003		2004		2005
Installment note payable to bank, payable in monthly installments of $3, bearing interest at 8%, due July 15, 2006; collateralized by real property		91		57		31
Installment note payable, principal and interest payable quarterly in varying amounts, noninterest-bearing, discounted at 5.5%, due December 2007		—		1,237		946
Installment note payable, principal and interest payable in annual installments of $550, noninterest-bearing, discounted at 5.5%, due September 2007		—		1,290		895
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 3.97% to 8.612%, due January 2005 through July 2010; collateralized by automobiles, machinery and equipment		845		1,787		3,347
		115,894		175,914		387,853
Less current maturities		742		1,728		134,805
	$	115,152	$	174,186	$	253,048

(1) In 1999, the Company entered into a credit agreement which provided a revolving credit line equal to the lesser of $100,000 or the borrowing base. In 2003, the Company entered into a restated credit agreement which provided a revolving credit line equal to the lesser of $200,000 or the borrowing base. In 2005, the Company entered into a restated credit agreement which provided a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base was $186,000 at December 31, 2004 and was scheduled to mature in June 2006. Under the restated credit agreement, the borrowing base was $270,000 at September 30, 2005 and matures in June 2009. Interest was paid quarterly on $90,000 and $66,389 based upon various LIBOR options as of December 31, 2004 (effective rate of 4.06% and 4.71%, respectively) and on $8,000 based on prime plus varying margins as of December 31, 2004 (effective rate of 5.75%). Under the restated credit agreement, interest is paid at least every three months on $208,500 and $9,000 based upon various LIBOR options as of September 30, 2005 (effective rate of 5.88% and 5.81%, respectively). As of September 30, 2005 we had $26,000 outstanding based on prime plus varying margins (effective rate of 7.25%). The credit line is collateralized by the Company’s oil and gas properties. Under the terms of the agreement, dividends may not exceed $350 per quarter. The agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting. The Company believes it was in compliance with the financial covenants at December 31, 2004 and September 30, 2005.

(2) In 2002, the Company entered into a credit agreement to provide funds to refinance existing indebtedness, provide construction financing for its office building and provide permanent financing upon completion of the construction. Total availability under the construction agreement of $6,750 had been advanced at December 31, 2004. Advances bear interest from the date of the advance at the national prime rate plus 0.25% with a minimum interest rate of 5% and a maximum rate of 9.5% (effective rate of 5.00% at December 31, 2004 and September 30, 2005). Monthly accrued interest payments began September 30, 2002 with monthly principal and interest payments beginning on June 30, 2004 after substantial completion of the construction. The note matures on August 31, 2010 and is collateralized by the property and all tangible and intangible property owned or acquired arising from the construction or ownership of the property.

F1-21

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Interest of $155 and $107 was capitalized during the years ended December 31, 2003 and 2004, respectively, primarily related to the construction of the Company’s office building and other construction projects.

Maturities of long-term debt are as follows:

	Year ended December 31, 2004		Nine months ended September 30, 2005
2005	$	1,728	$	610
2006		166,316		134,849
2007		1,692		2,278
2008		406		841
2009		463		244,038
2010 and thereafter		5,309		5,237
	$	175,914	$	387,853

Note 6: Capital leases

Future minimum lease payments under capital leases and the present value of the net minimum lease payments as of December 31, 2004 are as follows:

Year ending December 31
2005	$	589
2006		103
2007		94
2008		88
2009		19
Total minimum lease payments		893
Less amount representing interest		185
Present value of net minimum lease payments		708
Less current portion		431
	$	277

Note 7: Notes payable to members

The Company had notes payable to members of $1,031 at December 31, 2003, bearing interest at the national prime rate plus 3.00% (effective rate of 7.25% and 7.00% for the years ended December 31, 2003 and 2004, respectively), and collateralized by the assets of the Company.

F1-22

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Payments of principal and accrued interest aggregating $1,018 and $1,059 were made in 2003 and 2004, respectively. Payments included interest of $99 and $27 in 2003, and 2004, respectively. The notes were paid in full as of December 31, 2004.

Note 8: Income taxes

Income tax expense from continuing operations consists of the following for the years ended December 31:

	2002			2003		2004
Current tax expense (benefit)	$	(506	)	$	—	$	5
Deferred tax expense		3,640			6,932		9,624
	$	3,134		$	6,932	$	9,629

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

	2002		2003		2004
Statutory rate	34.0%		35.0%		35.0%
State income taxes, net of federal benefit	3.8%		2.6%		2.6%
Statutory depletion	(2.9%	)	(0.2%	)	(0.2%	)
Other	0.7%		0.3%		(1.6%	)
Effective tax rate	35.6%		37.7%		35.8%

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

	2003			2004
Deferred tax assets related to
Hedge instruments	$	3,453		$	8,414
Asset retirement obligations		717			899
Accrued expenses, allowance and other		588			331
Net operating loss carryforwards
Federal		6,232			6,973
State		2,421			1,127
Statutory depletion carryforwards		451			510
Alternative minimum tax credit carryforwards		190			206
		14,052			18,460
Deferred tax liabilities related to
Property and equipment		(26,052	)		(35,073	)
Inventories		(300	)		(350	)
		(26,352	)		(35,423	)
Net deferred tax liabilities	$	(12,300	)	$	(16,963	)

F1-23

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Approximately $2,641 and $5,192 of the current deferred tax asset at December 31, 2003 and 2004, respectively, relates to the short-term hedge instruments. Additionally, approximately $99 of the current deferred tax asset relates to asset retirement obligations at December 31, 2004. At December 31, 2003 and 2004, taxes receivable of $102 and $118, respectively, are included in accounts receivable.

The Company has federal net operating loss carryforwards of approximately $19,900 at December 31, 2004, which will begin to expire in 2022 if unused. At December 31, 2004, the Company has state net operating loss carryforwards of approximately $20,000, which will begin to expire in 2013. In addition, at December 31, 2004, the Company had tax percentage depletion carryforwards of approximately $1,400 which are not subject to expiration. A valuation allowance was not required for any period presented.

Note 9: Related party transactions

The Company manages, controls, administers and operates the properties and business and affairs of CEI Bristol. At December 31, 2003 and 2004, the Company had accounts receivable of $5,332 and $1,444, respectively, due from CEI Bristol. The Company acts as operator of certain partnership wells and receives overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were $1,630, $939, and $1,018 for the years ended December 31, 2002, 2003, and 2004, respectively. Additionally, the Company is compensated for management services provided to CEI Bristol through a management fee. Management fees earned by the Company were $79, $89, and $228 for the years ended December 31, 2002, 2003, and 2004, respectively.

Note 10: Deferred compensation

Effective January 1, 2004, the Company implemented a Phantom Unit Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom units may be awarded to participants in total up to 2% of the fair market value of the Company. 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 price strips. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Compensation expense is recognized over the vesting period of the phantom units. The Company recognized deferred compensation expense of $120 for the year ended December 31, 2004 related to the Plan.

F1-24

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 11: Retirement benefits

The Company provides a 401(k) retirement plan for all employees with at least one month of service. The Company matches employee contributions 100%, up to 5% of each employee’s gross wages. At December 31, 2003 and 2004, there were 191 and 207 employees, respectively, participating in the plan. Contributions recognized by the Company totaled $465 and $544 for the years ended December 31, 2003 and 2004, respectively.

Note 12: Divestiture

In 2002, the Company decided to exit the drilling business and the operations were subsequently sold effective May 28, 2002. The asset group sold was distinguishable as a component of the Company and met the criteria of accounting under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Accordingly, related operating results of the contract drilling operations were reported as discontinued operations. The Company incurred a loss on the sale of $617, net of tax benefit of $323, which was included in the loss from discontinued operations. For 2002, drilling revenues were $2,990 and pretax losses were $940.

Note 13: Commitments and contingencies

Standby Letters of Credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. The Company had various Letters outstanding totaling $800 and $990 as of December 31, 2003 and 2004, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 5.25% at December 31, 2004) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during 2003 or 2004.

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, 2002, 2003, and 2004 was $587, $568, and $486, respectively. Future minimum rental payments for the rental of equipment on oil and gas properties are approximately $450 and $75 for the years ended December 31, 2005 and 2006, respectively.

Various claims and lawsuits, incidental to the ordinary course of business, are pending both for and against the Company. In the opinion of management, all matters are not expected to have a material effect on the Company’s consolidated financial position or consolidated results of operations.

F1-25

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 14: Oil and gas activities

The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows for the years ended December 31:

	2002		2003		2004
Property acquisition costs	$	17,730	$	19,864	$	30,546
Development costs		21,343		36,758		62,371
Exploration costs		1,779		340		3,114
Total	$	40,852	$	56,962	$	96,031

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

	2003			2004
Proven oil and gas properties	$	184,667		$	274,466
Unproven oil and gas properties (excluded from amortization)		2,180			4,982
Accumulated depreciation, depletion, and amortization		(33,087	)		(48,384	)
Oil and gas properties, net	$	153,760		$	231,064

The average depreciation, depletion and amortization rate per equivalent mcf of production was $0.51, $0.53, and $0.81 for the years ended December 31, 2002, 2003, and 2004, respectively.

Oil and gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties, exploratory wells in progress, and secondary recovery projects before the assignment of proved reserves. Of the $4.98 million of unproved property costs at December 31, 2004 being excluded from the amortizable base, $291, $687, and $3,783 were incurred in 2002, 2003, and 2004, respectively, and $221 was incurred in prior years. These costs are primarily seismic and lease acquisition costs. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to five years.

Note 15: Disclosures about oil and gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Lee Keeling and Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual

F1-26

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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, 2002, 2003, and 2004 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2002	10,902		119,681		185,093
Purchase of minerals in place	5,111		18,153		48,819
Sales of minerals in place	(36	)	(374	)	(590	)
Extensions and discoveries	218		2,381		3,689
Revisions	809		19,441		24,295
Improved recoveries	30		443		623
Production	(791	)	(7,952	)	(12,698	)
Balance at December 31, 2002	16,243		151,773		249,231
Purchase of minerals in place	4,273		24,877		50,515
Sales of minerals in place	(118	)	(463	)	(1,171	)
Extensions and discoveries	254		11,242		12,766
Revisions	(3,498	)	21,090		102
Improved recoveries	547		4,920		8,202
Production	(924	)	(9,762	)	(15,306	)
Balance at December 31, 2003	16,777		203,677		304,339
Purchase of minerals in place	3,724		39,894		62,238
Sales of minerals in place	(91	)	(201	)	(747	)
Extensions and discoveries	1,589		24,470		34,004
Revisions	2,051		2,229		14,535
Improved recoveries(1)	19,150		5,474		120,374
Production	(1,173	)	(11,923	)	(18,961	)
Balance at December 31, 2004	42,027		263,620		515,782
Proved developed reserves:
December 31, 2002	11,616		125,784		195,480
December 31, 2003	14,314		160,662		246,546
December 31, 2004	17,358		186,544		290,692

(1) Includes 18,533 mbbls related to CO₂ tertiary recovery in 2004.

The following information was developed using procedures prescribed by SFAS No. 69. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

F1-27

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

• future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 3, “Hedge Activities and Financial Instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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

	2002			2003			2004
Future cash flows	$	1,128,319		$	1,678,196		$	3,324,252
Future production costs		(432,200	)		(560,129	)		(1,095,352	)
Future development and abandonment costs(1)		(37,409	)		(64,443	)		(325,115	)
Future income tax provisions		(210,326	)		(357,409	)		(657,950	)
Net future cash flows		448,384			696,215			1,245,835
Less effect of 10% discount factor		(230,118	)		(370,965	)		(689,309	)
Standardized measure of discounted future net cash flows	$	218,266		$	325,250		$	556,526

(1) Includes $177,357 added in 2004 for CO₂ tertiary recovery.

F1-28

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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 $10,268, $23,208, and $29,332 in 2002, 2003, and 2004, respectively.

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

	2002			2003			2004
Beginning of year	$	88,002		$	218,266		$	325,250
Sale of oil and gas produced, net of production costs		(24,502	)		(49,826	)		(78,472	)
Net changes in prices and production costs		123,548			101,115			89,687
Extensions and discoveries		7,194			22,194			56,933
Improved recoveries		1,450			22,546			143,366
Changes in future development costs		(20,746	)		(14,083	)		(69,721	)
Development costs incurred during the period that reduced future development costs		4,522			5,601			11,230
Revisions of previous quantity estimates		32,538			186			32,775
Purchases and sales of reserves in place, net		63,649			81,077			109,754
Accretion of discount		12,277			32,065			49,565
Net change in income taxes		(67,621	)		(64,588	)		(126,942	)
Changes in production rates and other		(2,045	)		(29,303	)		13,101
End of year	$	218,266		$	325,250		$	556,526

Average prices in effect at December 31, 2002, 2003, and 2004 used in determining future net revenues related to the standardized measure calculation are as follows:

	2002		2003		2004
Oil (per Bbl)	$	31.23	$	32.52	$	43.51
Gas (per Mcf)	$	4.59	$	6.19	$	6.35

Note 16: Comprehensive loss (unaudited)

Components of comprehensive income (loss), net of related tax, are as follows for the nine months ended September 30:

	2004			2005
Net income	$	11,399		$	9,964
Unrealized loss on hedges		(22,594	)		(80,148	)
Reclassification adjustment for hedge losses included in net income		8,010			17,225
Comprehensive loss	$	(3,185	)	$	(52,959	)

F1-29

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 17: Quarterly results (unaudited)

The following table sets forth selected unaudited consolidated quarterly statements of operations and production data for the seven quarters ended September 30, 2005.

	Three months ended
(Dollars in thousands, except share and per share amounts)	March 31, 2004			June 30, 2004			September 30, 2004			December 31, 2004			March 31, 2005			June 30, 2005			September 30, 2005
Revenues:
Oil sales	$	8,410		$	10,378		$	13,823		$	14,926		$	15,218		$	17,778		$	21,828
Gas sales		12,659			14,207			17,027			22,116			20,931			24,556			30,416
Oil and gas sales		21,069			24,585			30,850			37,042			36,149			42,334			52,244
Loss from hedge settlements		(1,862	)		(4,819	)		(5,796	)		(8,269	)		(4,472	)		(8,494	)		(15,097	)
Gain (loss) from hedge ineffectiveness		(843	)		(205	)		(548	)		992			(4,367	)		(80	)		(7,233	)
Loss from oil and gas hedging activities		(2,705	)		(5,024	)		(6,344	)		(7,277	)		(8,839	)		(8,574	)		(22,330	)
Total revenues		18,364			19,561			24,506			29,765			27,310			33,760			29,914
Costs and expenses:
Lease operating		5,276			6,536			6,530			7,050			7,641			9,551			8,573
Production tax and gas handling charges		1,960			1,962			2,615			3,271			3,645			3,447			4,983
Depreciation, depletion and amortization		3,499			3,856			4,204			6,675			7,198			7,439			8,452
General and administrative		1,532			1,124			1,817			1,512			2,300			1,860			2,471
Total costs and expenses		12,267			13,478			15,166			18,508			20,784			22,297			24,479
Operating income		6,097			6,083			9,340			11,257			6,526			11,463			5,435
Non-operating income (expense):
Interest income (expense)		(1,249	)		(1,310	)		(1,540	)		(2,063	)		(2,345	)		(2,704	)		(3,234	)
Other income		171			93			72			(57	)		136			165			223
Net non-operating expenses		(1,078	)		(1,217	)		(1,468	)		(2,120	)		(2,209	)		(2,539	)		(3,011	)
Income before income taxes		5,019			4,866			7,872			9,137			4,317			8,924			2,424
Income tax expense		1,796			1,742			2,820			3,271			1,681			3,507			513
Net income	$	3,223		$	3,124		$	5,052		$	5,866		$	2,636		$	5,417		$	1,911
Earnings per share:
Basic and diluted	$	3,223		$	3,124		$	5,052		$	5,866		$	2,636		$	5,417		$	1,911
Weighted average number of shares outstanding
Basic and diluted		1,000			1,000			1,000			1,000			1,000			1,000			1,000
Production volumes
Oil (MBbls)		246			279			327			321			332			350			344
Gas (MMcf)		2,500			2,646			3,095			3,682			3,698			3,771			3,987
Combined (MMcfe)		3,976			4,320			5,057			5,608			5,690			5,871			6,051

F1-30

Chaparral Energy, Inc. and subsidiaries

(formerly Chaparral, L.L.C. and subsidiaries)

Notes to consolidated financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Note 18: Event (unaudited) subsequent to date of auditors report

The Company paid dividends on October 3, 2005 of $350 and on January 3, 2006 of $350.

On December 1, 2005, the Company issued 8 ¹/2% Senior Notes in the amount of $325,000, due December, 1, 2015 with interest due semi-annually beginning June 1, 2006. The proceeds from the notes were used to pay the $132,000 bridge loan to General Electric Capital Corporation and reduce the amount outstanding under the Company’s revolving credit line.

In connection with the issuance of the 8 ¹/2% Senior Notes, the borrowing base under the Company’s revolving credit line was reduced from $270.0 million to $172.5 million.

F1-31

Report of independent registered public accounting firm

General Partner

CEI Bristol Acquisition, LP

We have audited the accompanying balance sheets of CEI Bristol Acquisition, LP as of December 31, 2003 and 2004, and the related statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of CEI Bristol Acquisition, LP as of December 31, 2003 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, effective January 1, 2003, the Partnership changed its method of accounting for asset retirement obligations.

GRANT THORNTON LLP

Oklahoma City, Oklahoma

September 28, 2005

F2-1

CEI Bristol Acquisition, LP

Balance sheets

	December 31,						September 30,
(in thousands)	2003			2004			2005
							(unaudited)
Assets
Current assets
Cash and cash equivalents	$	1,897		$	2,804		$	44,486
Accounts receivable		10,482			6,697			7,201
Other assets		262			1,282			520
Total current assets		12,641			10,783			52,207
Oil & gas properties, net, using the successful efforts methods		56,942			56,328			61,869
Other assets		10			3			—
	$	69,593		$	67,114		$	114,076
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	6,450		$	2,986		$	5,316
Current portion of notes payable		—			—			16,000
Short-term hedge instruments		8,006			10,387			42,108
Total current liabilities		14,456			13,373			63,424
Hedge instruments		9,641			11,295			—
Asset retirement obligations		215			254			1,001
Partners’ capital
Limited and general partners		61,893			63,221			88,949
Accumulated other comprehensive loss		(16,612	)		(21,029	)		(39,298	)
		45,281			42,192			49,651
	$	69,593		$	67,114		$	114,076

F2-2

CEI Bristol Acquisition, LP

Statements of operations

	Year ended December 31,									Nine months ended September 30,
(in thousands)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Revenues
Oil and gas sales	$	21,682		$	31,423		$	44,310		$	33,148		$	29,773
Hedge loss		(1,892	)		(9,424	)		(10,892	)		(7,767	)		(12,836	)
Total revenues		19,790			21,999			33,418			25,381			16,937
Costs and expenses
Lease operating		9,460			6,430			7,589			5,177			5,787
Production tax and gas handling charges		2,335			3,099			5,523			4,030			3,538
Depreciation, depletion and amortization		7,135			5,430			8,571			6,143			4,818
Impairment of oil and gas properties		1,783			3,764			2,180			1,134			—
General and administrative		180			202			351			303			196
Total costs and expenses		20,893			18,925			24,214			16,787			14,339
Operating income (loss)		(1,103	)		3,074			9,204			8,594			2,598
Other income (expense)		509			43			123			(39	)		20
Income (loss) before accounting change		(594	)		3,117			9,327			8,555			2,618
Cumulative effect of change in accounting principal		—			(35	)		—			—			—
Net income (loss)	$	(594	)	$	3,082		$	9,327		$	8,555		$	2,618

F2-3

CEI Bristol Acquisition, LP

Statement of partners’ capital

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

(unaudited)

(in thousands)	General Partner			Limited Partner			Accumulated other comprehensive loss			Total
Balance at January 1, 2002	$	625		$	61,873		$	(3,713	)	$	58,785
Net loss		(6	)		(588	)		—			(594	)
Other comprehensive loss
Reclassification adjustment for hedge losses		—			—			1,804			1,804
Unrealized loss on hedges		—			—			(11,621	)		(11,621	)
Total comprehensive loss											(10,411	)
Distributions		(39	)		(3,812	)		—			(3,851	)
Contributions		20			1,970			—			1,990
Balance at December 31, 2002		600			59,443			(13,530	)		46,513
Net income		31			3,051			—			3,082
Other comprehensive loss
Reclassification adjustment for hedge losses		—			—			8,477			8,477
Unrealized loss on hedges		—			—			(11,559	)		(11,559	)
Total comprehensive loss											—
Distributions		(85	)		(8,464	)		—			(8,549	)
Contributions		73			7,244			—			7,317
Balance at December 31, 2003		619			61,274			(16,612	)		45,281
Net income		93			9,234			—			9,327
Other comprehensive income
Reclassification adjustment for hedge losses		—			—			11,273			11,273
Unrealized loss on hedges		—			—			(15,690	)		(15,690	)
Total comprehensive income											4,910
Distributions		(152	)		(15,082	)		—			(15,234	)
Contributions		72			7,163			—			7,235
Balance at December 31, 2004		632			62,589			(21,029	)		42,192
Net income (unaudited)		26			2,592			—			2,618
Other comprehensive loss (unaudited)
Reclassification adjustment for hedge losses		—			—			10,679			10,679
Unrealized loss on hedges		—			—			(28,948	)		(28,948	)
Total comprehensive loss											(15,651	)
Distributions (unaudited)		(63	)		(6,229	)		—			(6,292	)
Contributions (unaudited)		454			28,948			—			29,402
Balance at September 30, 2005 (unaudited)		1,049			87,900			(39,298	)		49,651

F2-4

CEI Bristol Acquisition, LP

Statements of cash flows

	Year ended December 31,									Nine months ended September 30,
(in thousands)	2002			2003			2004			2004			2005
										(unaudited)			(unaudited)
Cash flows from operating activities
Net income (loss)	$	(594	)	$	3,082		$	9,327		$	8,555		$	2,618
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		7,135			5,430			8,571			6,143			4,818
Cumulative effect of accounting change		—			35			—			—			—
Impairment on oil and gas properties		1,783			3,764			2,180			1,134			—
(Gain) loss on hedge ineffectiveness		88			947			(381	)		112			2,157
Gain on sale of oil and gas properties		(494	)		(37	)		(42	)		120			—
Change in assets and liabilities
Decrease (increase) in accounts receivable		(714	)		(6,440	)		3,785			3,865			(504	)
(Increase) decrease in other assets		37			72			(1,020	)		119			761
(Increase) decrease in accounts payable and accrued liabilities		(690	)		3,675			(3,469	)		(3,653	)		1,320
Net cash provided by operating activities		6,551			10,528			18,951			16,395			11,170
Cash flows from investing activities
Purchase of oil and gas properties		(8,112	)		(8,863	)		(10,444	)		(6,877	)		(8,598	)
Proceeds from dispositions of oil and gas properties		4,060			785			399			389			—
Net cash used in investing activities		(4,052	)		(8,078	)		(10,045	)		(6,488	)		(8,598	)
Cash flows from financing activities
Proceeds from notes payable		—			—			—			—			16,000
Distributions to partners		(3,851	)		(8,549	)		(15,234	)		(11,895	)		(6,292	)
Capital contributions		1,990			7,317			7,235			2,988			29,402
Net cash (used in) provided by financing activities		(1,861	)		(1,232	)		(7,999	)		(8,907	)		39,110
Net increase in cash and cash equivalents		638			1,218			907			1,000			41,682
Cash and cash equivalents at beginning of year		41			679			1,897			1,897			2,804
Cash and cash equivalents at end of year	$	679		$	1,897		$	2,804		$	2,897		$	44,486

F2-5

Supplemental Disclosure of Noncash Investing Activities

During the years ended December 31, 2003 and 2004 and the nine months ended September 30, 2005, the Partnership recorded an asset and related liability of $9, $34, and $1,674 associated with the asset retirement obligation on acquisition and/or development of oil and gas properties.

Effective on January 1, 2003, the Company recorded the cumulative effect of SFAS No. 143 for asset retirement obligations, as follows:

Increase in oil and gas properties	$	167
Increase in asset retirement obligations		(202	)
Cumulative effect of accounting change	$	(35	)

F2-6

CEI Bristol Acquisition, LP

Notes to financial statements

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

(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of accounting policies

CEI Bristol Acquisition, LP (the “Partnership”) was organized effective February 10, 2000 under the laws of the state of Texas and commenced oil and gas operations on September 28, 2000. The Partner-ship is involved in the acquisition, drilling, development, and production of oil and gas properties.

The general partner receives 1% of revenue and expense items until repayment of the capital investment of the 99% limited partner. Once the limited partner has received cash distributions in the amount of capital contributions, plus amounts to yield an annual rate return of 11%, as defined by the “Cumulative Payout” agreement, the general partner will receive an additional 34% of revenues and expenses.

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

Interim financial statements

The financial information as of September 30, 2005 and for the nine months ended September 30, 2004 and 2005 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the nine month period ended September 30, 2005 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2005.

Use of estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management makes estimates based on knowledge and experience; accordingly, actual results could differ from those estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, asset retirement obligations and others, and are subject to change.

Cash and cash equivalents

The Partnership considers all highly liquid investments with maturities of three months or less to be cash equivalents.

The Partnership maintains its cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Partnership has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. At December 31, 2003 and 2004, the Partnership has cash and cash equivalents of approximately $1,472 and $2,380, respectively, at one financial institution. Cash and cash equivalents at September 30, 2005 included $42,108 used on October 3, 2005 to terminate the swaps.

F2-7

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Accounts receivable

The Partnership has receivables from oil and gas purchasers which are generally uncollateralized. The Partnership generally reviews these parties for credit worthiness and general financial condition. The Partnership maintains its allowance by considering the length of time past due and previous loss history among other things.

Oil and gas properties

The Partnership uses the successful efforts method of accounting for oil and gas properties and activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells which result in the discovery of proved reserves, and to drill and equip developmental wells are capitalized. Costs relating to unsuccessful exploration, geological and geophysical costs, costs of carrying and retaining unproved properties, and costs of abandoned properties are expensed.

Capitalized proved property acquisition costs are amortized by field using the unit-of-production method based on proved reserves. 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 proved developed reserves. The units-of-production method is based primarily on estimates of proved reserve quantities generally computed using the latest forward pricing curve. Due to uncertainties inherent in this estimation process, it is at least reasonably possible that reserve quantities will be revised in the near term.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized as income.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

The Partnership periodically reviews the carrying value of proved oil and gas properties for impairment based upon the future estimated undiscounted cash flows from these properties on a field-by-field basis. The Partnership’s estimated future cash flows and reserve quantities are based upon the latest current market prices generally using forward pricing curves at the time the impairment is determined, which may or may not reflect prices at the Partnership’s year-end. Based on this review, the carrying value of proved oil and gas properties that could not be recovered through these estimated cash flows are reduced to their fair value based upon estimated cash flows discounted at 10%. Significant unproved properties are assessed periodically on a prospect-by-prospect basis and any decline in fair value below cost is recorded as impairment

F2-8

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

expense. Unproved properties which are not individually significant are periodically assessed for impairment on a field-by-field basis using the Partnership’s drilling history and lease period.

Income taxes

Income taxes on net income of the Partnership are payable by the partners. Accordingly, no provision has been made for federal or state income taxes.

Revenue recognition

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

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its ratable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Partnership recognizes income on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their ratable share of gas, no liability is recorded for the Partnership’s obligation for natural gas taken by its purchasers which exceeds the Partnership’s ownership interest of the well’s total production. The Partnership’s aggregate imbalance due to over production is approximately 360,000 thousand cubic feet (mcf) of gas and 343,000 mcf at December 31, 2003 and 2004, respectively. The Partnership’s aggregate imbalance due to under production is approximately 1,236,000 mcf and 1,134,000 mcf at December 31, 2003 and 2004, respectively.

Financial instruments

The Partnership’s financial instruments include cash and cash equivalents, receivables, and hedge instruments. The carrying amounts of cash and cash equivalents and receivables approximate fair value due to their short-term nature. Derivative instruments are carried at fair value.

Hedge transactions

The Partnership uses swaps and collars to reduce the effect of fluctuations in crude oil and natural gas prices. The Partnership accounts for these transactions in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires that the Partnership recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation. Derivatives that are not hedges must be adjusted to fair value through income.

If the derivative is a hedge, depending on the nature of the hedge, changes in the fair value of derivatives will either be offset against the change in fair value of the hedged assets, liabilities,

F2-9

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

or firm commitments through income or recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value will be immediately recognized in income.

Under SFAS No. 133, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2003 or 2004.

Asset retirement obligations

On January 1, 2003, the Partnership adopted SFAS No. 143 Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of income. The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules.

Upon adoption in 2003, the Partnership recorded a net asset of $167, a related liability of $202 (using an 8.5% discount rate) and a cumulative loss effect of accounting change of $35. The pro forma balance of the asset retirement obligation at January 1, 2002 and 2003 would have been $170 and $202, respectively, and pro forma net income (loss) would have been ($515) and $3,117 for the years ended December 31, 2002 and 2003, respectively.

The activity incurred in the asset retirement obligation since adoption is as follows:

	As of December 31,						As of September 30,
	2003			2004			2005
Beginning balance	$	—		$	222		$	264
Adoption of SFAS No. 143		202			—			—
Liabilities incurred in current period		9			5			—
Liabilities settled in current period		(6	)		(12	)		(8	)
Accretion expense		17			21			92
Revisions of estimated cash flows		—			28			1,673
Ending ARO balance		222			264			2,021
Less current portion		7			10			1,020
	$	215		$	254		$	1,001

F2-10

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

Recently issued accounting standards

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

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 supersedes SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements, and APB Opinion No. 20, Accounting Changes. SFAS No. 154 requires, unless impracticable, retrospective application to prior periods’ financial statements of changes in accounting principle. The provisions of SFAS No. 154 also require that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. SFAS No. 154 is effective for all accounting changes made in fiscal years beginning after December 15, 2005.

Reclassifications

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

Note 2: Oil and gas properties

Oil and gas properties consist of the following at December 31:

	2003		2004
Leasehold costs	$	60,523	$	60,503
Tangible equipment costs		6,498		8,800
Intangible drilling costs		14,262		21,785
Asset retirement costs		171		196
		81,454		91,284
Less accumulated depletion, depreciation, and amortization		24,512		34,956
	$	56,942	$	56,328

Note 3: Hedging activities

The results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of this exposure, the Partnership has entered into derivative instruments. The Partnership’s derivative instruments covered approximately 56% and 44% of oil and gas production, respectively, for the year ended December 31, 2004. All derivative instruments have been entered into and designated as hedges of oil and gas price risk and not

F2-11

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

for speculative or trading purposes. As of December 31, 2004, the Partnership’s derivative instruments were comprised solely of swaps. For swap instruments, the Partnership receives a fixed price for the hedged commodity and pays a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount to or from the counterparty. These swaps have been designated and have qualified as cash flow hedge instruments.

The estimated fair values of derivative instrument liabilities as of December 31, 2004 were approximately $4,595 and $17,087 for oil swaps and gas swaps, respectively. The carrying values of these instruments are equal to the estimated fair values. The fair value of the derivative instruments was established using appropriate valuation methodologies in accordance with SFAS No. 133, as amended. The actual contribution to future results of operations will be based on the market prices at the time of settlement and may be more or less than fair value estimates used at the balance sheet dates.

Hedge loss reported in oil and gas sales is comprised of the following for the years ended December 31:

	Year Ended December 31,							Nine Months Ended September 30,
	2002		2003		2004			2004		2005
								(unaudited)		(unaudited)
Reclassification of settled contracts	$	1,804	$	8,477	$	11,273		$	7,655	$	10,679
(Gain) loss on ineffective portion of derivative qualifying for hedge accounting		88		947		(381	)		112		2,157
	$	1,892	$	9,424	$	10,892		$	7,767	$	12,836

The Partnership expects to transfer approximately $24,649 of the balance in accumulated other comprehensive loss, based upon market prices at September 30, 2005, to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of September 30, 2005 are expected to occur by December 1, 2007.

Note 4: Related party transactions

The general partner manages, controls, administers, and operates the business affairs of the Partnership. The Partnership compensates the general partner for services provided to the Partnership through a management fee. Management fees paid by the Partnership were approximately $79, $89 and $228 for the years ended December 31, 2002, 2003 and 2004, respectively.

The parent company of the general partner acts as operator of certain Partnership wells and receives overhead reimbursements as provided in operating agreements. Fees paid for these

F2-12

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

overhead reimbursements were approximately $1,630, $939 and $1,018 for the years ended December 31, 2002, 2003 and 2004. At December 31, 2003 and 2004, the Partnership had accounts payable of approximately $5,332 and $1,444 respectively, due to the parent company of the general partner.

Note 5: Oil and gas activities

The Company’s oil and gas activities are conducted entirely in the United States. Costs incurred in oil and gas producing activities are as follows for the years ended December 31:

	2002		2003		2004
Property acquisition costs	$	74	$	270	$	386
Development costs		7,684		8,610		9,903
Exploration costs		635		59		185
Asset retirement costs		—		171		25
Total	$	8,393	$	9,110	$	10,499

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

	2003			2004
Proven oil and gas properties	$	81,450		$	91,272
Unproven oil and gas properties		4			12
Accumulated depreciation, depletion, and amortization		(24,512	)		(34,956	)
Oil and gas properties, net	$	56,942		$	56,328

Note 6: Disclosures about oil and gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Lee Keeling and Associates, Inc., each independent petroleum and geological engineers, and the Company’s engineering staff, in accordance with the provisions of SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

F2-13

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

The Partnership’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Partnership’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2002, 2003, and 2004 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2002	2,865		54,841		72,031
Purchase of minerals in place	270		9,763		11,383
Sales of minerals in place	(316	)	(3,868	)	(5,764	)
Extensions and discoveries	4		757		781
Revisions	618		5,711		9,419
Improved recoveries	183		1,941		3,039
Production	(346	)	(4,819	)	(6,895	)
Balance at December 31, 2002	3,278		64,326		83,994
Purchase of minerals in place	121		2,405		3,131
Sales of minerals in place	(19	)	(13	)	(127	)
Extensions and discoveries	63		3,298		3,676
Revisions	(556	)	2,110		(1,226	)
Improved recoveries	98		977		1,565
Production	(277	)	(4,268	)	(5,930	)
Balance at December 31, 2003	2,708		68,835		85,083
Purchase of minerals in place	143		6,334		7,192
Sales of minerals in place	—		—		—
Extensions and discoveries	19		4,014		4,128
Revisions	186		(471	)	645
Improved recoveries	58		642		990
Production	(275	)	(6,315	)	(7,965	)
Balance at December 31, 2004	2,839		73,039		90,073
Proved developed reserves:
December 31, 2002	3,057		56,511		74,853
December 31, 2003	2,550		61,691		76,991
December 31, 2004	2,568		58,918		74,326

The following information was developed using procedures prescribed by SFAS No. 69. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

F2-14

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

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

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and

• future net revenues may be subject to different rates of income taxation.

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 3, “Hedge Activities and Financial Instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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

	2002			2003			2004
Future cash flows	$	362,422		$	440,169		$	530,846
Future production costs		(132,711	)		(157,055	)		(178,721	)
Future development and abandonment costs		(9,336	)		(8,419	)		(17,797	)
Net future cash flows		220,375			274,695			334,328
Less effect of 10% discount factor		(108,872	)		(134,255	)		(169,125	)
Standardized measure of discounted future net cash flows	$	111,503		$	140,440		$	165,203

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were

F2-15

CEI Bristol Acquisition, LP

Notes to financial statements—(continued)

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

(dollars in thousands, unless otherwise noted)

included in the computation, then future cash flows would have decreased by $19,908, $24,647 and $22,272 in 2002, 2003, and 2004, respectively.

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

	2002			2003			2004
Beginning of year	$	58,413		$	111,503		$	140,440
Sale of oil and gas produced, net of production costs		(9,887	)		(21,894	)		(31,198	)
Net changes in prices and production costs		15,318			9,439			9,986
Extensions and discoveries		1,296			5,123			2,471
Improved recoveries		8,683			9,664			5,696
Changes in future development costs		(5,207	)		2,501			(6,846	)
Development costs incurred during the period that reduced future development costs		194			1,361			2,491
Revisions of previous quantity estimates		9,681			(1,797	)		1,121
Purchases and sales of reserves in place, net		15,133			15,296			17,468
Accretion of discount		5,841			11,150			14,044
Changes in production rates and other		12,038			(1,906	)		9,530
End of year	$	111,503		$	140,440		$	165,203

Average prices in effect at December 31, 2002, 2003, and 2004 used in determining future net revenues related to the standardized measure calculation are as follows:

	2002		2003		2004
Oil (per Bbl)	$	31.23	$	32.55	$	43.46
Gas (per Mcf)	$	4.59	$	5.83	$	6.19

Note 7: Event (unaudited) subsequent to date of auditors report

On September 30, 2005, the limited partner interest of the Partnership was purchased by an affiliate of the general partner. As a part of the purchase, the Partnership borrowed $16,000 from General Electric Capital Corporation (GECC) and received a $26,108 contribution from the general partner. These proceeds were used to fund the settlement of the Partnership’s hedges on October 3, 2005. The $16,000 owed to GECC is part of a $132,000 note payable due June 30, 2005, bears interest at LIBOR plus 2% and is collateralized by the oil and gas properties of the Partnership.

On December 1, 2005, the parent company of the general partner issued 8 ¹/2% Senior Notes in the amount of $325,000, due December 1, 2015. The proceeds from the notes were used to pay the $132,000 note payable, including the $16,000 owed by the Partnership.

On December 31, 2005, the Partnership was dissolved and all assets were transferred to the parent of the general and limited partner or its subsidiaries.

F2-16

Proved reserves at year-end

Annual production

Proved reserves replacement ratio

                     shares

Common stock

Prospectus

JPMorgan

Banc of America Securities LLC Lehman Brothers

Comerica Securities Fortis Securities

                    , 2006

Until                     , 2006 (25 days after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Part II

Information not required in prospectus

Item 13. Other expenses of issuance and distribution

The following table sets forth the costs and expenses to be paid by us in connection with the sale of the shares of common stock being registered hereby. All amounts are estimates except for the SEC registration fee, the NASD filing fee and the NYSE listing fee.

Securities and Exchange Commission registration fee	$	36,915
NASD filing fee		35,000
NYSE listing fee
Accounting fees and expenses		100,000
Legal fees and expenses		250,000
Printing and engraving expenses		250,000
Transfer agent and registrar fees and expenses		5,000
Other expenses
Total	$	2,000,000

Item 14. Indemnification of directors and officers

We are 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:

• for any breach of the director’s duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

• under section 174 of the Delaware General Corporation Law regarding unlawful dividends and stock purchases; or

• for any transaction for which the director derived an improper personal benefit.

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.

II-1

As permitted by Delaware law, our bylaws provide that:

• we may indemnify our other employees and agents, subject to very limited exceptions;

• we are required to advance expenses (including without limitation, attorneys’ fees), as incurred, to our directors and officers in connection with a legal proceeding, subject to very limited exceptions; and

• the rights conferred in our bylaws are not exclusive.

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 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.

Item 15. Recent sales of unregistered securities

The following is a description of all securities that the registrant has sold within the past three years without registering the securities under the Securities Act:

Chaparral Energy, Inc. was incorporated in the state of Delaware on September 14, 2005 as a wholly owned subsidiary of Chaparral, L.L.C. for the sole purpose of merging with Chaparral, L.L.C. At the time of formation, Chaparral Energy, Inc. issued 1,000 shares of its common stock to Chaparral, L.L.C., its sole stockholder, for $1,000 in a transaction exempt from registration requirements pursuant to Section 4(2) of the Securities Act of 1933, as amended. Chaparral, L.L.C. merged with and into Chaparral Energy, Inc. effective September 16, 2005, with Chaparral Energy, Inc. surviving the merger. At the effective time of the merger, all shares of capital stock of Chaparral Energy, Inc. issued and outstanding prior to the merger were cancelled and all units of Chaparral, L.L.C. issued and outstanding prior to the merger were converted to shares of the surviving entity, Chaparral Energy, Inc.

On December 1, 2005, we sold $325.0 million aggregate principal amount of our 8 ¹/2% Senior Notes due 2015 to J.P. Morgan Securities Inc., Banc of America Securities LLC, Lehman Brothers Inc., Comerica Securities, Inc., Fortis Securities, Inc. and RBS Greenwich Capital Inc., as the initial purchasers, in a transaction exempt from registration requirements pursuant to Section 4(2) of the Securities Act of 1933, as amended. The initial purchasers will resell the 8 ¹/2% Senior Notes due 2015 in private transactions in conformance with Rule 144A or Regulation S under the Securities Act of 1933. The net proceeds from the offering was approximately $316.0 million after deducting the initial purchasers’ discounts and estimated offering expenses. We used the net proceeds from the sale of our 8 ¹/2% Senior Notes due 2015 to repay approximately $184.0 million of the outstanding indebtedness on our Sixth Restated Credit Agreement and the $132.0 million outstanding under the bridge loan facility with General Electric Capital Corporation.

II-2

Item 16. Exhibits and financial statement schedules

(a) The following exhibits are filed herewith:

Number	Exhibit
1.1***	Form of Underwriting Agreement
3.1***	Form of Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc.
3.2*	Agreement and Plan of Merger, dated as of September 15, 2005, by and between Chaparral Energy, Inc. and Chaparral, L.L.C.
3.3***	Form of Amended and Restated Bylaws of Chaparral Energy, Inc.
4.1***	Specimen Common Stock Certificate
4.2*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.3)
4.3*	Indenture, dated as of December 1, 2005, among Chaparral Energy, Inc., as issuer, the subsidiaries of Chaparral Energy, Inc. party thereto as guarantors and Wells Fargo Bank, National Association, as trustee
4.4***	Registration Rights Agreement, by and between Chaparral Energy, Inc. and the Mark A. Fischer 1994 Trust, the Susan L. Fischer 1994 Trust and Altoma Energy G.P. dated February     , 2006
5.1***	Opinion of Andrews Kurth LLP
10.1*	Sixth Restated Credit Agreement, dated as of June 22, 2005, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein, as amended by the First Amendment dated as of September 30, 2005
10.2*	First Amendment to Sixth Restated Credit Agreement dated as of September 30, 2005
10.3*	Second Amendment to Sixth Restated Credit Agreement dated as of December 1, 2005
10.4*	Form of Mortgage
10.5*	Limited Partner Interest Purchase and Sale Agreement, dated September 29, 2005, by and between TIFD III-X LLC and CEI Acquisition, L.L.C.
10.6†***	Form of Indemnification Agreements, between Chaparral Energy, Inc. and each of the directors and executive officers thereof
10.7†*	Form of Assignment of Overriding Royalty Interest to James M. Miller
10.8†**	Phantom Unit Plan
10.9†**	Letter Agreement dated June 14, 2005 re: Conditional Employment Offer with Joseph O. Evans
21.1***	Subsidiaries of Chaparral Energy, Inc.
23.1**	Consent of Grant Thornton LLP
23.2**	Consent of Cawley, Gillespie & Associates, Inc.
23.3**	Consent of Lee Keeling & Associates, Inc.
23.4***	Consent of Andrews Kurth LLP (included in Exhibit 5.1)

* Previously filed.

** Filed herewith.

*** To be filed by amendment.

† Management contract or compensatory plan or arrangement.

(b) All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

II-3

Item 17. Undertakings

The undersigned Registrant hereby undertakes to provide to the Underwriters at the closing specified in the Underwriting Agreement certificates in such denominations and registered in such names as required by the Underwriters to permit prompt delivery to each purchaser.

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.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

II-4

Signatures

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Oklahoma City, Oklahoma, on this 14^th day of February, 2006.

CHAPARRAL ENERGY, INC.
By:	/S/    MARK A. FISCHER
Name:	Mark A. Fischer
Title:	President and Chief Executive Officer

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.

Signature	Title	Date
/S/    MARK A. FISCHER         Mark A. Fischer	President, Chief Executive Officer and Chairman (Principal Executive Officer)	February 14, 2006
/S/    JOSEPH O. EVANS         Joseph O. Evans	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	February 14, 2006
/S/    CHARLES A. FISCHER, JR.         Charles A. Fischer, Jr.	Director	February 14, 2006

II-5

Exhibit index

Number	Exhibit
1.1***	Form of Underwriting Agreement
3.1***	Form of Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc.
3.2*	Agreement and Plan of Merger, dated as of September 15, 2005, by and between Chaparral Energy, Inc. and Chaparral, L.L.C.
3.3***	Form of Amended and Restated Bylaws of Chaparral Energy, Inc.
4.1***	Specimen Common Stock Certificate
4.2*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.3)
4.3*	Indenture, dated as of December 1, 2005, among Chaparral Energy, Inc., as issuer, the subsidiaries of Chaparral Energy, Inc. party thereto as guarantors and Wells Fargo Bank, National Association, as trustee
4.4***	Registration Rights Agreement, by and between Chaparral Energy, Inc. and the Mark A. Fischer 1994 Trust, the Susan L. Fischer 1994 Trust and Altoma Energy G.P. dated February     , 2006.
5.1***	Opinion of Andrews Kurth LLP
10.1*	Sixth Restated Credit Agreement, dated as of June 22, 2005, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein, as amended by the First Amendment dated as of September 30, 2005
10.2*	First Amendment to Sixth Restated Credit Agreement dated as of September 30, 2005
10.3*	Second Amendment to Sixth Restated Credit Agreement dated as of December 1, 2005
10.4*	Form of Mortgage
10.5*	Limited Partner Interest Purchase and Sale Agreement, dated September 29, 2005, by and between TIFD III-X LLC and CEI Acquisition, L.L.C.
10.6†***	Form of Indemnification Agreements, between Chaparral Energy, Inc. and each of the directors and executive officers thereof
10.7†*	Form of Assignment of Overriding Royalty Interest to James M. Miller
10.8†**	Phantom Unit Plan
10.9†**	Letter Agreement dated June 14, 2005 re: Conditional Employment Offer with Joseph O. Evans
21.1***	Subsidiaries of Chaparral Energy, Inc.
23.1**	Consent of Grant Thornton LLP
23.2**	Consent of Cawley, Gillespie & Associates, Inc.
23.3**	Consent of Lee Keeling & Associates, Inc.
23.4***	Consent of Andrews Kurth LLP (included in Exhibit 5.1)

* Previously filed.

** Filed herewith.

*** To be filed by amendment.

† Management contract or compensatory plan or arrangement.