10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

Form 10-K/A

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file no. 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	73-1590941
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
701 Cedar Lake Boulevard Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code:

(405) 478-8770

Securities registered pursuant to Section 12(b) of the Act:

None.

Securities registered pursuant to Section 12(g) of the Act:

None.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  ¨    No   x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.     Yes  ¨    No  x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act). (Check one)

Large Accelerated Filer  ¨    Accelerated Filer   ¨    Non-Accelerated Filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes    ¨    No   x

The aggregate market value of voting stock held by non-affiliates of the registrant is not determinable as such shares were privately placed and there is no public market for such shares.

877,000 shares of the registrant’s Common Stock were outstanding as of December 20, 2007.

Explanatory Note

Chaparral Energy, Inc. (also referred to as the “Company,” “we,” or “our”) is filing this Amendment No. 1 (the “Amendment No. 1”) to our Form 10-K for the fiscal year ended December 31, 2006 (the “Form 10-K”), originally filed with the Securities and Exchange Commission on April 2, 2007, for the purpose of revising footnote 16 of the Notes to consolidated financial statements included herein in connection with certain revisions made to our proved reserves attributed to the polymer project in the North Burbank Unit. We have also made conforming revisions throughout Items 1. and 2. Business and Properties, Item 1A. Risk Factors, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 6-10, 13-16, 23, 25, 32 and 33. The revisions to the footnote have not been deemed material by us. Accordingly, no additional revisions or restatements to our consolidated financial statements are required or have been made.

Other than as set forth above, the information set forth in our consolidated financial statements and the footnotes thereto in this Amendment No. 1 has not been modified or updated in any way from the information in our financial statements and the related footnotes included in the Form 10-K. This Amendment No. 1 speaks as of the original filing date of the Form 10-K and reflects only the changes to the footnotes referenced above. No other information included in the Form 10-K has been modified or updated.

CHAPARRAL ENERGY, INC.

Index to Form 10-K

Part I	6
Items 1. and 2. Business and Properties	6
Item 1A. Risk Factors	22
Item 1B. Unresolved Staff Comments	29
Item 3. Legal Proceedings	29
Item 4. Submission of Matters to a Vote of Security Holders	29
Part II	29
Item 5. Market Price for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6. Selected Financial Data	30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	47
Item 8. Financial Statements and Supplementary Data	49
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
Item 9A. Controls and Procedures	74
Item 9B. Other Information	74
Part III	74
Item 10. Directors, Executive Officers and Corporate Governance	74
Item 11. Executive Compensation	76
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	87
Item 13. Certain Relationships and Related Transactions, and Director Independence	87
Item 14. Principal Accounting Fees and Services	89
Part IV	91
Item 15. Exhibits and Financial Statement Schedules	91
Signatures	94

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. 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 report.

Undue reliance should not be placed on forward-looking statements, which speak only as of the date of this report. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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Glossary of terms

The terms defined in this section are used throughout this Form 10-K:

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.
Basin	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Field	An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Fully developed finding, development and acquisition cost (FD&A)	Total costs incurred plus the increase in future development costs divided by total proved reserve acquisitions, extensions and discoveries and revisions.
Henry Hub spot price	The price of natural gas, in dollars per MMbtu, being traded at the Henry Hub in Louisiana in transactions for next-day delivery, measured downstream from the wellhead after the natural gas liquids have been removed and a transportation cost has been incurred.
Horizontal drilling	A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
Infill wells	Wells drilled into the same pool as known producing wells.
MBbl	One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf	One thousand cubic feet of natural gas.
Mcfe	One thousand cubic feet of natural gas equivalents.
MMBbl	One million barrels of crude oil, condensate or natural gas liquids.
MMBtu	One million British thermal units.
MMcf	One million cubic feet of natural gas.
MMcfe	One million cubic feet of natural gas equivalents.

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NYMEX	The New York Mercantile Exchange.
Net acres	The percentage of total acres an owner has out of a particular number of acres, or in 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 unique 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.
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.

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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.
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 through 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.

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PART I

Unless the context requires otherwise, references in this annual report to “Chaparral”, “Company”, “we”, “our”, “ours” and “us” refer to Chaparral Energy, Inc. and its predecessor, Chaparral L.L.C. and its subsidiaries on a consolidated basis. As used in this annual report, “pro forma basis” means after giving pro forma effect to our 2006 acquisition of Calumet Oil Company and certain of its affiliates. We have provided definitions of terms commonly used in the oil and gas industry in the “Glossary of terms” beginning on page 3.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Chaparral Energy, Inc.

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include additional areas of Ark-La-Tex, North Texas, the Gulf Coast and the Rocky Mountains. On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates (“Calumet”) for a cash purchase price of approximately $500.0 million. Calumet owned properties principally located in Oklahoma and Texas, areas which were complementary to our existing core areas of operations. As of December 31, 2006, estimated proved reserves attributable to the acquisition were approximately 346 Bcfe. Calumet’s proved reserves are relatively long-lived, have relatively low production decline rates and are approximately 96% oil. In addition to increasing our current average net daily production, many of the acquired properties have significant drilling and enhanced oil recovery opportunities.

As of December 31, 2006, we had estimated proved reserves of 906 Bcfe (69% proved developed and 59% crude oil) with a PV-10 value of approximately $1.5 billion. For the year ended December 31, 2006, our average daily production was 88.7 MMcfe and on a proforma basis was 112.2 MMcfe. As of December 31, 2006, our estimated pro forma reserve life was 22.1 years (calculated as December 31, 2006 reserves of 905,579 MMcfe divided by year ended December 31, 2006 pro forma production of 40,953 MMcfe). For the year ended December 31, 2006, our revenues were $249.2 million. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 16.

For the period from 2003 to 2006, our proved reserves and production grew at a compounded annual growth rate of 44% and 28%, respectively. We have grown primarily through a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. We currently expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

For the year ended December 31, 2006, we made capital expenditures of $667.1 million, including $129.7 million for development drilling and $489.1 million for acquisitions, of which $464.9 million were oil and gas properties acquired as part of the Calumet acquisition. The majority of our capital expenditures for developmental drilling in 2007 are allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower-risk.

Business Strengths

Consistent track record of low-cost reserve additions and production growth. From 2003 to 2006, we have grown reserves and production by a compounded annual growth rate of 44% and 28%, respectively. We have achieved this through a combination of drilling success and acquisitions. Our reserve replacement ratio, which reflects our reserve additions in a given period stated as a percentage of our production in the same period, has averaged nearly 500% per year since 1999. We replaced approximately 794%, 822% and 991% of our production in 2004, 2005 and 2006 respectively, at an average fully developed FD&A cost of $2.37 per Mcfe over this three-year period.

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Disciplined approach to proved reserve acquisitions. We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence, with reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2004, 2005 and 2006, our capital expenditures for acquisitions of proved properties were $28.5 million, $216.7 million and $484.4 million, respectively. These acquisition capital expenditures represented approximately 30%, 65% and 73%, respectively, of our total capital expenditures for those periods. In October 2006, we acquired Calumet, which added approximately 346 Bcfe of proved reserves as of December 31, 2006. Excluding the acquisition of Calumet, we spent $19.5 million on acquisitions of proved properties during 2006, representing approximately 10% of total capital expenditures for that period. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

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 strings, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.

Inventory of drilling locations. As of December 31, 2006, we had an inventory of over 740 proved developmental drilling locations and over 2,600 additional potential drilling locations, which combined represent over 17 years of drilling opportunities based on our 2006 drilling rate as shown in the following table.

	Identified proved undeveloped drilling locations	Identified additional potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net
Mid-Continent	571	1,609	367,476	37,460
Permian Basin	65	807	50,518	17,883
Ark-La-Tex	6	18	14,190	—
North Texas	36	99	16,286	763
Rocky Mountains	56	73	13,995	9,256
Gulf Coast	7	41	45,503	9,139
Total	741	2,647	507,968	74,501

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 22. We have experienced a high historical drilling success rate of approximately 97% on a weighted average basis during 2004, 2005 and 2006. For the year ended December 31, 2006, we spent $133.5 million to drill 61 operated wells and to participate in 131 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 42,400 square miles of 3-D seismic data, conducted four proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

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, and we also have specific software for modeling CO₂ enhanced recovery. We own a 29% interest in and operate a large CO₂ tertiary flood unit in southern Oklahoma and installed and operate a second tertiary

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flood unit with a 54% interest in the Oklahoma panhandle. At December 31, 2006, our proved reserves included four properties where CO₂ tertiary recovery methods are used, which comprise approximately 6% of our total proved reserves. With the acquisition of Calumet, and specifically the North Burbank Unit, our tertiary recovery assets include an enhanced oil recovery “EOR” polymer flood. The North Burbank Unit is in the early phases of an EOR polymer flood which was proven up by Phillips Petroleum Company through a pilot program in the mid 1980’s before being shut down due to low prevailing oil prices. We plan to expand this EOR program and ultimately to include CO₂ injection.

Experienced management team. Mark A. Fischer, our CEO and founder who beneficially owns 42.5% of our outstanding common stock, has operated in the oil and gas industry for 34 years after starting his career at Exxon as a petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in the 25.6% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 22 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Joe Evans, our Chief Financial Officer, has over 27 years of experience in the oil and gas industry. Individuals in our 24-person management team have an average of over 25 years of experience in the oil and gas industry.

Business Strategy

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

Continue lower-risk development drilling program. During the year ended December 31, 2006, we spent approximately $129.7 million on development drilling, which represents 19% of our capital expenditures for such period. A majority of these drilling wells are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

Acquire long-lived properties with enhancement opportunities. We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. In the last two years we have also made larger acquisitions that complemented our existing properties in our core areas. During the year ended December 31, 2006, we made acquisitions of approximately $489.1 million, or 73% of our total capital expenditures for such period.

Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 17 field offices throughout Oklahoma, Texas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor.

Expand CO₂ enhanced oil recovery activities. We have accumulated interests in 52 properties in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in certain of these properties. We began CO₂ injection in our Perryton Unit in December 2006 and plan to begin CO₂ injection in our NW Camrick Unit in 2007. To support our existing CO₂ tertiary recovery projects, we currently inject approximately 40 MMcf per day of CO₂. We have a 100% ownership interest in our 86 mile Borger CO₂ pipeline, a 29% interest in the 120 mile Enid to Purdy CO₂ pipeline, a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline and recently purchased 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and Southwestern Kansas that will enhance our CO₂ plans in this area.

Pursue modest exploration program. In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $10.0 million, or approximately 5% of our 2007 capital expenditures, on exploration activities.

Control operations and costs. We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancing, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and gas production to maximize both volumes and wellhead price. As of December 31, 2006, we operated properties comprising approximately 83% of our proved reserves.

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Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our proved developed production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of December 31, 2006, we had swaps in place for approximately 59% and 16% of our most recent internally estimated proved developed gas production for 2007 and 2008, respectively. We also had swaps in place for approximately 80% of our most recent internally estimated proved developed oil production for 2007 through 2011. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities of $21.4 million, $68.3 million and $4.2 million for the years ended December 31, 2004, 2005 and 2006, respectively, through a period of increasing commodity prices.

Oklahoma Ethanol L.L.C.

In August 2005, we entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma 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 between $115 million and $125 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $69 million to $75 million in secured indebtedness with recourse limited to our interests in this entity to fund construction costs and for related start-up working capital. We expect construction to commence in late 2007 with completion in 2009, and that our equity contribution will be approximately $30 million to $33 million.

Properties

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

	Proved reserves as of December 31, 2006							Average daily production (MMcfe per day)	Pro forma average daily production (MMcfe per day)
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	Percent of total MMcfe		PV-10 value ($mm)		Year ended December 31, 2006	Year ended December 31, 2006
Mid-Continent	73,312	251,293	691,165	76.4	%	$	1,087.4	53.3	76.8
Permian Basin	6,039	58,233	94,467	10.4	%		170.6	15.1	15.1
Ark-La-Tex	1,077	18,919	25,381	2.8	%		47.9	4.7	4.7
North Texas	2,324	5,008	18,952	2.1	%		38.4	3.1	3.1
Rocky Mountains	3,563	7,679	29,057	3.2	%		56.7	3.3	3.3
Gulf Coast	2,063	34,179	46,557	5.1	%		93.1	9.2	9.2
Total	88,378	375,311	905,579	100.0	%	$	1,494.1	88.7	112.2

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and gas properties is geographically diversified, 78% of our 2006 production was concentrated in our two core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2006 we owned interests in 7,687 gross (2,415 net) producing wells and we operated wells representing 83% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

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Mid-Continent

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2006, accounted for 76% of our proved reserves and 73% of our PV-10 value. We own an interest in 4,954 producing wells in the Mid-Continent, of which we operate 1,940. Our ten largest properties and 14 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2006, our net average daily production in the Mid-Continent Area was approximately 57.7 MMcfe per day, or 65% of our total net average daily production (or approximately 81.2 MMcfe per day, or 72% of our total net average daily production, on a pro forma basis). 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 approximately 4% of our proved reserves and PV-10 value at December 31, 2006. This area consists of three unitized fields, the Camrick Unit, which covers 9,080 acres, the NW Camrick Unit, which covers 4,080 acres and the Perryton Unit, which covers 2,040 acres. We currently operate these three fields with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs at a depth of approximately 6,800 feet. The three units have produced approximately 16.1 MMBbl of primary reserves and approximately 13.4 MMBbl of secondary reserves. There are approximately 35 active producing wells in this area. Currently CO₂ injection operations are continuing in the Phase I and II areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Unit from approximately 115 Bbls per day in 2001 from 11 wells to approximately 979 Bbls per day currently from 28 wells. The Phase II expansion at Camrick is currently underway. We plan to expand CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU represents 3% of our proved reserves and PV-10 value at December 31, 2006. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1966, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have approximately 22 active producing wells in this unit. Since January 2005, we have re-entered three wells, drilled one well and are scheduled to drill an additional four wells in 2007.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. We own approximately 6,600 net 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 26 Cleveland Sand producing wells, and we drilled three wells in each of 2005 and 2006. We have drilled two wells to date in 2007 and have plans to drill an additional ten wells in the remainder of 2007. Horizontal drilling technology has been employed in the most recently drilled wells. We expect that future wells will utilize horizontal technology.

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. 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 46 active producing wells in this unit.

Harmon County 3-D Shoot—Harmon County, Oklahoma. We have leased in excess of 29,000 acres in Harmon County, Oklahoma and have conducted a proprietary 3-D seismic shoot on this acreage. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling of the first four well package is complete. Completion procedures are underway on the wells with the initial well testing at rates of 92 Bbl per day and 250 Mcf per day from the Mississippi. With these positive test results, there is potential to drill additional wells on this acreage.

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CO₂ Enhanced Recovery Operations—Various counties, Oklahoma and Texas. We have initiated CO₂ injection in our Perryton Unit in December 2006 and plan to initiate CO₂ injection in our NW Camrick Unit in 2007. We have in place transportation and supply agreements to provide the necessary CO₂ for these projects. With the expansion at Camrick and the additions of these fields, we have increased our CO₂ volumes transported to 23 MMcf per day. Including properties recently purchased in the Calumet acquisition, we have accumulated 52 properties in Oklahoma and Texas that meet our criteria for CO₂ tertiary recovery operations. We have a 100% ownership and operate our 86 mile Borger CO₂ pipeline, own a 29% interest in the 120 mile Enid to Purdy CO₂ pipeline, and own a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline and recently purchased 100% interest in approximately 126 miles of pipeline located in the Panhandle of Oklahoma and Southwestern Kansas that will enhance our CO₂ plans in this area. Arrangements to secure additional sources of CO₂ are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in April 2005 estimating that significant oil reserves could be technically recovered in the State of Oklahoma through CO₂ enhanced oil recovery processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

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

North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is the largest property in the Calumet acquisition. The field was developed in the early 1920’s and is 23,080 acres in size and has a cumulative production of 316 million Bbls of oil (primary and secondary). The producing zone is Red Fork and Bartlesville and occurs at a depth of 3,000 feet. We own 99.25% of the field and we are also the operator. As of December 31, 2006, the field was producing 1,340 Bbls per day from 214 producing wells. There are also 134 injection wells and 597 temporarily abandoned wells at this time. Upside potential exist in restoring a majority of the temporarily abandoned wells to production and in expanding the polymer EOR program that Phillips Petroleum Company instituted in the field from 1980-1986 as a pilot on 1,440 acres. Production increased from 500 Bbls per day to 1,200 Bbls per day in this pilot area as a result of the polymer injection program. The pilot was shut down in 1986 due to low oil prices. We have already reinstituted a polymer flood on 320 acres adjacent to Block A on a 19 well pattern. We have already returned 6 temporarily abandoned wells to production with rates of production as high as 15 Bbls per day. We believe that this field also may have upside with the injection of CO₂ in conjunction with expanding the polymer program.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit which is 2,235 acres was discovered in 1915 and unitized in 1977. We operate this unit with a working interest of 79.44%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 14 MMBbls of oil and the unit currently has 60 producing wells and 46 injection wells. As of December 31, 2006, production was 378 Bbls per day. We are currently in the completion phase of a 4 well pilot drilling program to increase density drill the Fox Deese Springer Unit from its current 10 acre spacing to 5 acre spacing. If this 4 well pilot program proves successful, we estimate 80 additional locations could be drilled. Additional potential exists in waterflood pattern modification and CO₂ EOR recovery.

Sivells Bend Unit—Cooke County, Texas. The Sivells Bend Unit is 3,863 acres in size, produces primarily from the Strawn, which occurs at a depth of 9,000 feet, and has recovered 39 MMBbls of oil to date. There are currently 29 producing wells and 13 injection wells, with production as of December 31, 2006 of approximately 301 Bbls of oil per day. Upside potential exists in increased density drilling from 80 acres to 40 acres in the Strawn. The only 40 acre increased density well drilled in the unit has recovered over 390 MBbls. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls per day in 1964 in the adjacent East Sivells Bend Unit and one well in our unit tested 104 Bbls per day for a short time. 3D seismic will be required to better define the fault blocks for an Ellenburger test. We own approximately 1,000 acres of fee minerals in this Sivells Bend Unit and own approximately half of the rights below the Strawn, which includes the Ellenburger.

Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2006, accounted for 10% of our proved reserves and 11% of our PV-10 value. We own an interest in 1,487 wells in the Permian Basin, of which we operate 312. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2006, our net average daily production in the Permian Basin Area was approximately 11.6 MMcfe per day, or 13% of our total net average daily production. Similar to the Mid-Continent Area, it is characterized by its stable long-life, shallow decline reserves.

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Tunstill Field Play—Loving and Reeves Counties, Texas. Our original Tunstill Field Play covers approximately 6,480 acres. We operate these wells with a working interest of 100%. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds while more recent wells have established production from the deeper Cherry Canyon Sands as well as the shallower sands. During 2006, we drilled ten wells in this play. We have plans to drill 11 additional wells in 2007. We have acquired leasehold rights to approximately 13,360 acres that are an expansion to our original Tunstill field play.

Haley Area: Atoka, Strawn and Morrow Play—Loving County, Texas. The Haley Area: Atoka, Strawn and Morrow Play encompasses 3,840 gross acres. We own interests in and operate seven producing wells in this play. Production has been established from three main intervals: the Atoka at a depth of approximately 16,000 feet, the Strawn at a depth of approximately 15,500 feet and the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Atoka, two are completed in the Strawn 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 Atoka/Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. We have recently drilled and completed two wells in this area. The Haley 36-4 is currently producing approximately 5,800 Mcf per day from the Morrow Sand. The Haley 38-2 is currently producing from the Atoka Lime and has developed Bone Springs behind pipe. We have scheduled to drill an offset to test this Bone Springs in the second quarter. If this Bone Springs proves productive, additional developmental wells will follow. We also have one additional Morrow test planned for this year.

Ark-La-Tex

Ark-La-Tex is one of our four growth areas and, as of December 31, 2006, accounted for 3% of our proved reserves and 3% of our PV-10 value. We own an interest in 128 wells in the Ark-La-Tex area, of which we operate 53. These reserves are characterized by shorter life and higher initial potential.

Giddings North Edwards—Fayette County, Texas. We control 4,780 acres in the Gidding North Edwards Field. We operate this field with an average working interest of 98%. Ten wells are producing from the Edwards Lime that occurs at a depth of 10,100 feet. These ten wells have produced 573 MBbls of oil and 44.2 Bcf of natural gas. We have recently leased an additional 1,200 acres adjacent to this field.

Winnsboro Field—Wood County, Texas. We control approximately 1,072 acres in the Winnsboro Field and operate 9 wells. Primary objectives in this field are the Travis Peak and Cotton Valley that occur at depths from 8,600 to 10,300 feet. Additional potential pay zones are the Sub-Clarksville, Bacon Lime, Hill, Gloyd and the Pettit-Pittsburg that occur at depths from 4,150 to 8,500 feet. During 2005 we drilled one development well in this field.

North Texas

North Texas is the second of our four growth areas and, as of December 31, 2006, accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 772 wells in the North Texas area, of which we operate 115. One of our three proprietary 3-D seismic shoots has been completed in this area.

Percy Jones Clearfork Play—Howard and Mitchell Counties, Texas. We own and operate the Percy Jones, Percy Jones A and Percy Jones B leases, encompassing 640 acres in the Laton East Howard Field. We currently operate these properties with an average working interest of 100%. A total of 54 wells have been completed in the Glorieta at depths of 2,500 feet and Upper Clearfork at depths of 2,700 feet since its discovery in 1947. The Percy Jones lease (north half of Section 13) has a total of 25 producing wells and is developed on 10 acre spacing with some increased density development to 5 acres and cumulative production of 2.7 MMBbls of oil and 24 MMcf of natural gas. The Percy Jones A and B leases make up the south half of the section, have a total of 11 existing wells and have cumulative production of 495 MBbls of oil and 22 MMcf of natural gas. Secondary recovery through water injection has proven successful in offset leases but has been done on a very limited basis in the Percy Jones lease.

Recent increased density drilling activity in the Laton East Howard Field, as well as patterned waterflood development has shown marked success. This type of development in the Percy Jones leases has the potential to increase reserves since much of the south half of the section, which has only 11 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.

Eanes Units—Montague County, Texas. We own and operate the North Eanes, East Eanes and South Eanes Units. These units cover approximately 7,000 acres and produce from the Caddo and Atoka at approximately 5,600 to 5,700 feet.

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We currently operate these units with an average working interest of 95%. We have conducted an 11.5 square mile proprietary 3-D seismic program in these units. Potential pay zones have been identified in the Caddo at 5,600 feet, Atoka at 5,700 feet, Barnett shale at 6,000 feet, Mississippian Reef at 6,300 feet, Viola at 6,500 feet and the Ellenberger at 6,800 feet. We have approximately 29 active producing wells in this area. We drilled six wells in 2005 with completion and testing finished in 2006 with all wells completed successfully. We have scheduled to drill three wells in 2007.

Rocky Mountains

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

Bakken Horizontal Play—Richland County, Montana. In 2005, we drilled a dual leg horizontal well in the Bakken interval on acreage we own that was producing from the Red River formation. The McVay #2-34H well was drilled as a horizontal dual leg lateral with the first lateral measuring 3,648 feet in length and the second lateral measuring 3,496 feet in length. As of March 1, 2007, the well was producing 135 Bbls of oil per day and 215 Mcf of natural gas per day.

We recently leased approximately 9,400 net acres in the immediate area of the McVay #2-34H and have drilled five additional wells in 2006 with initial rates ranging from 130 Bbls of oil per day to 375 Bbls of oil per day. We have two additional wells scheduled to be drilled in 2007.

Gulf Coast

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

Mustang Island & Mesquite Bay—Nueces County, TX. We control approximately 2,618 net 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 9 active producing wells in this area. We recently shot and are currently processing a 3D seismic survey over parts of this area in an attempt to find bypassed reserves or other potential reservoirs.

Vivian Borchers Area—Lavaca County, Texas. We control approximately 1,300 acres in the Vivian Borchers Area. 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, 2006. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (44% of PV-10 value) and by Lee Keeling & Associates, Inc. (41% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (15% of PV-10 value).

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	Net proved reserves
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	PV-10 value (In thousands)
Developed—producing	45,899	233,606	509,000	$	949,472
Developed—non-producing	11,925	48,352	119,902		189,768
Undeveloped	30,554	93,353	276,677		354,823
Total proved	88,378	375,311	905,579	$	1,494,063

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

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

(Dollars in thousands, except prices)	2004		2005		2006
Future net revenue	$	1,663,141	$	3,597,300	$	3,518,020
PV-10 value		775,116		1,602,610		1,494,063
Standardized measure of discounted future net cash flows		514,041		1,067,888		1,082,209
Oil price (per Bbl)	$	43.51	$	61.04	$	61.06
Natural gas price (per Mcf)	$	6.35	$	10.08	$	5.64

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

The following table sets forth information at December 31, 2006 relating to the producing wells in which we owned a working interest as of that date. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells is the total number of producing wells in which we have an interest, and net wells is the sum of our working interest in all wells.

	Total wells
	Gross	Net
Crude oil	5,401	1,791
Natural gas	2,286	624
Total	7,687	2,415

The following table details our gross and net interest in producing wells in which we have an interest and the number of wells we operated at December 31, 2006 by area.

	Total wells		Operated Wells
	Gross	Net
Mid-Continent	4,954	1,766	1,940
Permian Basin	1,487	316	312
Ark-La-Tex	128	53	53
North Texas	772	120	115
Rocky Mountains	155	41	42
Gulf Coast	191	119	127
Total	7,687	2,415	2,589

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

	Developed		Undeveloped
	Gross	Net	Gross	Net
Mid-Continent	912,483	367,476	46,826	37,460
Permian Basin	87,568	50,518	19,687	17,883
Ark-La-Tex	25,687	14,190	—	—
North Texas	21,489	16,286	965	763
Rocky Mountains	41,384	13,995	19,129	9,256
Gulf Coast	78,372	45,503	15,265	9,139
Total	1,166,983	507,968	101,872	74,501

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 a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir beyond one location. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.

	2004				2005				2006
	Gross		Net		Gross		Net		Gross		Net
Development wells
Productive	89.0		24.4		171.0		52.0		189.0		56.1
Dry	5.0		2.8		2.0		0.8		1.0		0.2
Exploratory wells
Productive	1.0		0.1		11.0		6.0		1.0		1.0
Dry	—		—		1.0		0.4		1.0		0.1
Total wells
Productive	90.0		24.5		182.0		58.0		190.0		57.1
Dry	5.0		2.8		3.0		1.2		2.0		0.3
Total	95.0		27.3		185.0		59.2		192.0		57.4
Percent productive	95	%	90	%	98	%	98	%	99	%	99	%

The following table summarizes our estimates of net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates (using prices in effect on December 31, 2004, 2005 and 2006), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2004, 2005 and 2006 were prepared by Cawley, Gillespie & Associates (44% of PV-10 value in 2006) and Lee Keeling & Associates, Inc. (41% of PV-10 value in 2006), both independent petroleum engineering firms, and our engineering staff (15% of PV-10 value in 2006).

	As of December 31,
Proved Reserves	2004			2005			2006
Oil (Mbbl)		28,585			33,913			88,378
Natural gas (MMcf)		263,620			414,384			375,311
Natural gas equivalent (MMcfe)		435,130			617,862			905,579
Proved developed reserve percentage		67	%		69	%		69	%
PV-10 value (in thousands)	$	775,116			1,602,610			1,494,063
Estimated reserve life (in years)(1)		22.9			24.4			28.0
Cost incurred (in thousands):
Property acquisition costs
Proved properties(2)	$	28,483		$	216,742		$	484,404
Unproved properties		2,063			5,543			4,731
Total acquisition costs		30,546			222,285			489,135
Development costs		62,371			103,479			170,987
Exploration costs		3,114			7,274			7,015
Total	$	96,031		$	333,038		$	667,137
Annual reserve replacement ratio(3)		794	%		822	%		991	%
Three-year average fully developed FD&A cost ($/Mcfe)(4)				$	1.82		$	2.37

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

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

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

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

	2003		2004		2005			2006
Purchases of minerals in place		50,515		62,238		173,176			354,004
Extensions and discoveries		12,766		34,004		22,531			16,736
Revisions		102		14,535		(7,516	)		(56,423	)
Improved recoveries		8,202		39,722		20,262			6,653
Total reserve additions		71,585		150,499		208,453			320,970
Costs incurred	$	56,962	$	96,031	$	333,038		$	667,137
Changes in future development costs		20,494		121,938		154,042			236,700
Total costs incurred	$	77,456	$	217,969	$	487,080		$	903,837
Three-year average fully developed FD&A cost ($/Mcfe)					$	1.82		$	2.37

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

	Year ended December 31,
	2004		2005		2006
Production:
Oil (MBbl)		1,173		1,449		1,906
Natural Gas (MMcf)		11,923		16,660		20,949
Combined (MMcfe)		18,961		25,354		32,385
Average daily production:
Oil (Bbls)		3,214		3,970		5,222
Natural gas (Mcf)		32,666		45,644		57,395
Combined (Mcfe)		51,950		69,464		88,727
Average prices (before effect of hedges):
Oil (per Bbl)	$	40.53	$	53.76	$	61.65
Natural Gas (per Mcf)		5.54		7.41		6.29
Combined (per Mcfe)		5.99		7.94		7.69
Average costs per Mcfe:
Lease operating	$	1.42	$	1.66	$	2.21
Production tax	$	0.44	$	0.58	$	0.58
Depreciation, depletion, and amortization	$	0.92	$	1.24	$	1.61
General and administrative	$	0.32	$	0.39	$	0.45

Non-GAAP Financial Measure and Reconciliation

The PV-10 value (PV-10) is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at December 31, 2006 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 as of December 31, 2006 for our major areas of operation:

(dollars in millions)	PV-10 Value		Present value of future income tax discounted at 10%		Standardized measure of discounted future net cash flow
Mid-Continent	$	1,087.4	$	254.2	$	833.2
Permian Basin		170.6		64.3		106.3
Ark-La-Tex		47.9		16.6		31.3
North Texas		38.4		15.1		23.3
Rocky Mountains		56.7		18.3		38.4
Gulf Coast		93.1		43.4		49.7
Total	$	1,494.1	$	411.9	$	1,082.2

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;

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• 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 the Federal Energy Regulatory Commission (FERC), as well as nondiscriminatory access requirements, could further increase the availability of gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of gas sales from our wells.

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

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

Environmental Matters and Regulation

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

General

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

• require the acquisition of various permits before drilling commences;

• require the installation of expensive pollution control equipment;

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

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

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

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

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

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

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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 years ended December 31, 2005 and 2006, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. In connection with our Calumet acquisition in October 2006, we identified certain properties with potential minor remediation needs. As of December 31, 2006, the Company has accrued a liability of $1.6 million for site restoration costs associated with oil and gas properties acquired from Calumet. Management continues to evaluate potential environmental liabilities and the recording of the purchase price allocation. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2007 or that will otherwise have a 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.

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.

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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.

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

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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 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. 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.

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Natural Gas Gathering Regulations

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

State Regulation

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

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

Seasonality

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

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 December 31, 2006, we had 497 full-time employees, including 11 geologists and geophysicists, 26 production and reservoir engineers and 11 land professionals. Of these, 213 work in our Oklahoma City office and 284 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.

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ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

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 senior secured credit facility, our Senior Notes, or make planned capital expenditures.

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

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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 report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses from the development and production of oil and gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the Commission, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 2006 future cash flows used realized prices based on a Henry Hub spot price of $5.64 per MMBtu for natural gas and a WTI Cushing spot price of $61.06 per Bbl for oil.

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

As of December 31, 2006, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

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 December 31, 2006, our total debt was $976.3 million. Our maximum commitment amount and the borrowing base under our new Seventh Restated Credit Agreement was $750.0 million and $750.0 million, respectively. After the issuance of our 8 ⁷/ 8% Senior Notes on January 18, 2007, our maximum commitment amount and the borrowing base were reduced to $652.0 million and $500.0 million, respectively. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

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

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

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

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

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• 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 Senior Notes, the lenders or noteholders may declare the principal of, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

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

Availability under our new Seventh Restated Credit Agreement is subject to a borrowing base, which initially was $750.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. As a result of the issuance of our 8 ⁷/8% Senior Notes on January 18, 2007, our maximum commitment amount and borrowing base were adjusted to $652.0 million and $500.0 million, respectively. 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 debt financing. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of

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oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on an economic basis to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves.

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

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 31% of our total estimated proved reserves (by volume) at December 31, 2006 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and enhanced recovery operations. Our historical December 31, 2006 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14.3%, 11.0% and 8.6% during 2007, 2008 and 2009, respectively. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.

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

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. 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 cancelled as a result of numerous factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failures or accidents;

• adverse weather conditions;

• compliance with environmental and other governmental requirements; and

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

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

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

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

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

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• unitization and pooling of properties;

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

• well stimulation processes;

• produced water disposal;

• safety precautions;

• operational reporting; and

• taxation.

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

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

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

• other environmental damages.

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

Our use of derivative instruments could result in financial losses or reduce our income.

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the New York Mercantile Exchange, or NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. As of December 31, 2006, we had entered into swaps for 15,530 MMcf of our natural gas production for 2007 through 2008 at average monthly prices ranging from $6.96 to $10.15 per Mcf of natural gas. As of December 31, 2006, we had entered into swaps for 9,805 MBbl of our crude oil production for 2007 through 2011 at average monthly prices ranging from $57.86 to $68.34 per Bbl of oil. As of December 31, 2006, we had basis protection swaps for 20,750 Mcf for 2007 through 2009 at average monthly prices ranging from $0.77 to $1.17 per mcf. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2006 was a liability of approximately $7.1 million. Derivative instruments expose us to risk of financial loss in some circumstances, including when:

• our production is less than expected;

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

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

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be offset against the change in fair value of the hedged assets, liabilities or firm commitments through income, or will be recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, will be immediately recognized in income. If it is probable the oil or gas sales which are hedged will not occur or the hedge is not highly effective, hedge accounting is discontinued and the effect is immediately recognized in income.

Under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2004, 2005, or 2006.

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

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

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

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices. However, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted.

We may not be able to successfully integrate Calumet’s operations with our operations.

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

• operating a significantly larger combined company;

• experiencing operational interruptions or the loss of key employees, customers or suppliers; and

• consolidating other corporate and administrative functions.

The combined company is also exposed to risks that are commonly associated with transactions similar to the acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all.

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

        We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our CEO, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. These persons include the executive officers listed in Item 10 under “Executive Officers and Directors.” Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

If Mark A. Fischer ceases to be either our Chairman, CEO or President in connection with a change of control, such event could also result in a change of control event occurring under our senior credit agreement, the indenture governing our outstanding senior notes or our Phantom Unit Plan.

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

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

• injury or loss of life;

27

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

• pollution or other environmental damage;

• clean-up responsibilities;

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

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

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

Costs of environmental liabilities could exceed our estimates.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated 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 our Credit Agreement as of December 31, 2006 were 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 $750.0 million, equal to our borrowing base at December 31, 2006, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $7.5 million.

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

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

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In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of non-performance 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. 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.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET PRICE FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has not been registered under the Securities Exchange Act of 1934, and there is no established public trading market for our common equity.

As of March 16, 2007, we had 877,000 shares of common stock outstanding held by three record holders.

Cash dividends of $3.4 million and $1.0 million were paid during the years ended December 31, 2005 and 2006, respectively. Dividends of $0.4 million were paid on a quarterly basis from January 1, 2005 through September 30, 2006 and a one-time dividend of $2.0 million was paid on February 1, 2005. We do not currently 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 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 restricted in our ability to pay dividends under our Credit Agreement.

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ITEM 6. SELECTED 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 report. The financial data as of and for each of the five years ended December 31, 2006 were derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.

	Year Ended December 31,
(Dollars in thousands, except share and per share amounts)	2002			2003			2004			2005			2006
Operating results data:
Revenues
Oil and gas sales	$	42,653		$	74,186		$	113,546		$	201,410		$	249,180
Loss on oil and gas hedging activities		(749	)		(12,220	)		(21,350	)		(68,324	)		(4,166	)
Total revenues		41,904			61,966			92,196			133,086			245,014
Costs and expenses
Lease operating		15,037			19,520			26,928			42,147			71,663
Production taxes		3,114			4,840			8,272			14,626			18,710
Depreciation, depletion and amortization		7,910			10,376			17,533			31,423			52,299
General and administrative		4,059			4,946			5,985			9,808			14,659
Total costs and expenses		30,120			39,682			58,718			98,004			157,331
Operating income		11,784			22,284			33,478			35,082			87,683
Non-operating income (expense)
Interest expense		(3,998	)		(4,116	)		(6,162	)		(15,588	)		(45,246	)
Non-hedge derivative losses		—			—			—			—			(4,677	)
Other income		1,012			208			279			665			792
Net non-operating expense		(2,986	)		(3,908	)		(5,883	)		(14,923	)		(49,131	)
Income from continuing operations before income taxes, minority interest and accounting change		8,798			18,376			27,595			20,159			38,552
Income tax expense		3,134			6,932			9,880			7,309			14,817
Minority interest		—			—			—			—			(71	)
Income from continuing operations before accounting change		5,664			11,444			17,715			12,850			23,806
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		$	17,715		$	12,850		$	23,806
Income per share from continuing operations (basic and diluted)	$	7.31		$	14.77		$	22.86		$	16.58		$	29.74
Income (loss) per share from accounting change, net		—			(1.15	)		—			—			—
Income (loss) per share from discontinued operations, net		(0.80	)		—			—			—			—
Net income per share (basic and diluted)	$	6.51		$	13.62		$	22.86		$	16.58		$	29.74
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			775,000			775,000			775,000			800,500
Cash flow data:
Net cash provided by operating activities	$	17,480		$	32,541		$	46,870		$	55,744		$	89,198
Net cash used in investing activities		(27,505	)		(55,213	)		(92,141	)		(325,068	)		(703,848	)
Net cash provided by financing activities		8,921			26,146			54,061			257,080			621,855

30

	As of December 31,
(Dollars in thousands)	2002			2003			2004			2005			2006
Financial position data:
Cash and cash equivalents	$	1,578		$	5,052		$	13,842		$	1,598		$	8,803
Total assets		142,919			211,086			308,827			647,379			1,331,435
Total debt		91,780			118,355			176,622			446,544			976,272
Retained earnings		20,420			30,977			48,692			58,126			80,883
Accumulated other comprehensive loss, net of income taxes		(3,733	)		(4,900	)		(12,107	)		(47,967	)		(3,946	)
Total equity		16,688			26,078			36,586			10,167			177,864
Cash dividends per common share		—			—			—		$	4.40		$	1.35

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ITEM 7. 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 report.

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

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, Ark-La-Tex, North Texas and the Rocky Mountains. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and enhanced oil recovery projects. As of December 31, 2006, we had estimated proved reserves of 906 Bcfe, with a PV-10 value of $1.5 billion. Our reserves were 69% proved developed and 59% crude oil.

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

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and natural gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 14.3%, 11.0% and 8.6% during 2007, 2008 and 2009, respectively. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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 and amount of future drilling, development and abandonment activities;

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

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

32

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

• Stock Split. On September 27, 2006, we effected a 775-for-1 stock split in the form of a stock dividend to shareholders of record as of September 26, 2006. All share and per share amounts for all periods discussed and disclosed within this report have been restated to reflect this stock split.

• Private equity sale. On September 29, 2006, we closed the sale of an aggregate of 102,000 shares of Chaparral’s common stock to Chesapeake Energy Corporation for an aggregate purchase price of $102.0 million. Proceeds from the sale after commissions and expenses were approximately $100.9 million and were used for general corporate and working capital purposes and acquisitions of oil and gas properties.

• Acquisition of Calumet Oil Company and affiliates. On October 31, 2006, we acquired all of the outstanding capital stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates for a cash purchase price of approximately $500.0 million. Calumet owns properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations. Proved reserves attributable to the acquisitions were in excess of 347 Bcfe. Calumet’s proved reserves are long-lived, have low production decline rates and are approximately 96% oil. In addition to increasing our current average net daily production, many of the properties have significant drilling and enhanced oil recovery opportunities. Additionally, as part of the transaction, we acquired Calumet’s hedging arrangements, which included hedge swaps of 75 MBbls of oil per month at $66.10 per barrel during 2006, 75 MBbls per month at $63.00 per barrel during 2007 and 30 MBbls per month at $68.10 during 2008.

• Seventh Restated Credit Agreement. In conjunction with the purchase of Calumet, we entered into a Seventh Restated Credit Agreement (“Credit Agreement”). As of October 31, 2006, upon the completion of the Calumet acquisition, we had $629.0 million outstanding under our Credit Agreement. As of December 31, 2006, we had $637.0 million outstanding under the Credit Agreement.

• Production Tax Credit. During 2006, the Company purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. The Company’s expected return on the investment will be receipt of $2 of tax credits for every $1 invested to be recouped from our Oklahoma production taxes. The investments will be accounted for as a production tax benefit asset and will be netted against tax credits realized in other income using the effective yield method over the expected recovery period.

• Oklahoma Ethanol. In August 2005, we entered a joint venture, Oklahoma Ethanol, L.L.C. to construct and operate an ethanol production plant in Oklahoma. We spent approximately $0.6 million toward the design for the construction of the plant for the year ended December 31, 2006.

• CEI-Bristol. 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 $158.1 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.

• Green Country Supply Acquisition. On December 21, 2006, we entered into a non-binding letter of intent to purchase all of the outstanding shares of stock of Green Country Supply, Inc. “GCS” for $25.0 million. The agreement is subject to completion of due diligence and the negotiation of a definitive stock purchase agreement and is not expected to close before April 2007. We expect that the purchase agreement will contain a number of customary closing conditions. No assurance can be given that a purchase agreement will be entered into upon these or other terms. GCS is owned by the former shareholders of Calumet Oil Company and provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

• 8 ⁷/8% Senior Notes due 2017. On January 18, 2007, we issued $325.0 million aggregate principal amount of 8 ⁷/8% Senior Notes maturing on February 1, 2017. The net proceeds from the issuance of the notes was used to pay down outstanding amounts under our Credit Agreement.

33

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

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

	Year ended December 31,				Percentage Increase (Decrease)
	2005		2006
Oil and gas sales (dollars in thousands)
Oil	$	77,899	$	117,504	50.8	%
Gas		123,511		131,676	6.6	%
Total	$	201,410	$	249,180	23.7	%
Production
Oil (MBbls)		1,449		1,906	31.5	%
Gas (MMcf)		16,660		20,949	25.7	%
MMcfe		25,354		32,385	27.7	%
Average sales prices (excluding hedging)
Oil per Bbl	$	53.76	$	61.65	14.7	%
Gas per Mcf		7.41		6.29	(15.1	)%
Mcfe	$	7.94	$	7.69	(3.2	)%

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

Production volumes by area were as follows (MMcfe):

	Year ended December 31,		Percent Increase
	2005	2006
Mid Continent	17,588	21,051	19.7	%
Permian	2,847	4,246	49.1	%
Ark-La-Tex	2,692	3,172	17.8	%
North Texas	770	1,007	30.8	%
Rockies	723	999	38.2	%
Gulf Coast	734	1,910	160.2	%
Totals	25,354	32,385	27.7	%

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

	Year ended December 31,
(dollars in thousands)	2005			2006
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(53,584	)	$	(22,927	)
Hedge ineffectiveness		(14,740	)		18,761
Total	$	(68,324	)	$	(4,166	)

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

34

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

	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge
Oil (per Bbl):
Year ended December 31, 2005	$	53.76	$	36.43	67.8	%
Year ended December 31, 2006		61.65		47.32	76.8	%
Gas (per Mcf):
Year ended December 31, 2005	$	7.41	$	4.82	65.0	%
Year ended December 31, 2006		6.29		7.39	117.5	%

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

	Amount						Per Mcfe
	Year ended December 31,				Percent Increase		Year ended December 31,				Percent Increase
(dollars in thousands)	2005		2006				2005		2006
Lease operating expenses	$	42,147	$	71,663	70.0	%	$	1.66	$	2.21	33.1	%
Production taxes		14,626		18,710	27.9	%		0.58		0.58	0.0	%
Depreciation, depletion and amortization		31,423		52,299	66.4	%		1.24		1.61	29.8	%
General and administrative		9,808		14,659	49.5	%		0.39		0.45	15.4	%

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

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

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

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

Interest expense. Interest expense increased by $29.7 million, or 190%, compared to 2005, primarily as a result of increased levels of borrowings and higher interest rates paid. Approximately $25.9 million of the increase is due to the issuance of the 8 ¹/2% Senior Notes on December 1, 2005.

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

35

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004

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

	Year ended December 31,				Percentage Increase
	2004		2005
Oil and gas sales (dollars in thousands)
Oil	$	47,537	$	77,899	63.9	%
Gas		66,009		123,511	87.1	%
Total	$	113,546	$	201,410	77.4	%
Production
Oil (MBbls)		1,173		1,449	23.5	%
Gas (MMcf)		11,923		16,660	39.7	%
MMcfe		18,961		25,354	33.7	%
Average sales prices (excluding hedging)
Oil per Bbl	$	40.53	$	53.76	32.6	%
Gas per Mcf		5.54		7.41	33.8	%
Mcfe	$	5.99	$	7.94	32.6	%

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

Production volumes by area were as follows (MMcfe):

	Year ended December 31,		Percent Increase
	2004	2005
Mid Continent	14,818	17,588	18.7	%
Permian	2,261	2,847	25.9	%
Ark-La-Tex	749	2,692	259.4	%
North Texas	567	770	35.8	%
Rockies	208	723	247.6	%
Gulf Coast	358	734	105.0	%
Totals	18,961	25,354	33.7	%

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

	Year ended December 31,
(dollars in thousands)	2004			2005
Loss from oil and gas hedging activities:
Hedge settlements	$	(20,746	)	$	(53,584	)
Hedge ineffectiveness		(604	)		(14,740	)
Total	$	(21,350	)	$	(68,324	)

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

36

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

	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge
Oil (per Bbl):
Year ended December 31, 2004	$	40.53	$	29.16	71.9	%
Year ended December 31, 2005		53.76		36.43	67.8	%
Gas (per Mcf):
Year ended December 31, 2004	$	5.54	$	4.86	87.7	%
Year ended December 31, 2005		7.41		4.82	65.0	%

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

	Amount						Per Mcfe
	Year ended December 31,				Percent Increase		Year ended December 31,				Percent Increase
(dollars in thousands)	2004		2005				2004		2005
Lease operating expenses	$	26,928	$	42,147	56.5	%	$	1.42	$	1.66	16.9	%
Production taxes		8,272		14,626	76.8	%		0.44		0.58	31.8	%
Depreciation, depletion and amortization		17,533		31,423	79.2	%		0.92		1.24	34.8	%
General and administrative		5,985		9,808	63.9	%		0.32		0.39	21.9	%

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

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

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $13.1 million. For oil and gas properties, $7.0 million of the increase was due to higher production volumes in 2005 and $6.1 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production on oil and gas properties increased by $0.32 to $1.09 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. Approximately $0.5 million of the increase is due to professional fees associated with documenting our internal controls over financial reporting for compliance with the Sarbanes-Oxley Act of 2002. The remainder of the G&A expense is net of $6.2 million in 2005 and $4.2 million in 2004 capitalized as part of our exploration and development activities.

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

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Liquidity and Capital Resources

Overview. Our primary sources of liquidity are cash generated from our operations, issuance of equity and our revolving credit line. At December 31, 2006, we had approximately $8.8 million of cash and cash equivalents and $112.1 million of availability under our revolving credit line with a borrowing base of $750.0 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, capital requirements and contingencies for the next 12 months. We may adjust our planned capital expenditures depending on the timing and amount of any equity funding received and the availability of acquisition opportunities that meet our investment criteria.

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

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

Capital expenditures. For the year ended December 31, 2006, we incurred actual costs as summarized by area in the following table:

(Dollars in thousands)	For the year ended December 31, 2006(1)		Percent of total
Mid-Continent(2)	$	547,873	82.1	%
Permian Basin		49,510	7.4	%
Ark-La-Tex		5,194	0.8	%
North Texas		17,154	2.6	%
Rocky Mountains		15,804	2.4	%
Gulf Coast		31,602	4.7	%
	$	667,137	100.0	%

(1) Includes $10.8 million of additions relating to increases in Chaparral’s asset retirement obligations.

(2) Includes $464.9 million of costs related to the acquisition of Calumet.

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

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

(Dollars in thousands)	For the year ended December 31, 2006(1)		2007 budgeted capital expenditures(3)
Development activities:
Developmental drilling	$	127,280	$	122,000
Enhancements		31,036		30,000
Tertiary recovery		12,671		20,000
Acquisitions:
Proved properties(2)		484,404		30,000
Unproved properties		4,731		—
Exploration activities		7,015		10,000
Total	$	667,137	$	212,000

(1) Includes $10.8 million of additions relating to increases in Chaparral’s asset retirement obligations.

(2) The 2007 acquisition budget does not include $25 million that we may pay for the acquisition of Green Country Supply, Inc., or an anticipated ethanol plant investment of approximately $30 to $33 million.

(3) Our current 2007 capital expenditure budget for oil and gas properties is $212.0 million assuming we receive net proceeds from an issuance of our equity during 2007.

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

(Dollars in thousands)	2007 drilling capital expenditures		Percent of total
Mid-Continent	$	89,000	58.5	%
Permian Basin		29,000	19.1	%
Ark-La-Tex		5,000	3.3	%
North Texas		11,000	7.2	%
Rocky Mountains		6,000	4.0	%
Gulf Coast		12,000	7.9	%
	$	152,000	100.0	%

A majority of our capital expenditure budget for development drilling in 2007 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells. We also have budgeted increased capital expenditures for our CO₂ tertiary recovery projects in the Mid-Continent and Permian Basin.

We continually evaluate our capital needs and compare them to our estimated funds available. Our actual expenditures during fiscal 2007 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 adjusted by associated hedging activities. We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the year ended December 31, 2006, the net cash provided from operations was approximately 38% of our net cash used in investing activities excluding the Calumet acquisition. For the year ended December 31, 2006, cash flow from operating activities increased by 60% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue and reduced settlement losses on hedging activities partially offset by higher operating expense.

Our current credit facility. As of December 31, 2006, we had $637.0 million outstanding under our Credit Agreement and the borrowing base was $750.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of December 31, 2006.

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Our Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2005 and 2006, our current ratio as computed using generally accepted accounting principles was 0.65 and 0.88, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.05 and 2.15, 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, 2005			December 31, 2006
Current assets per GAAP	$	77,255		$	91,863
Plus—Availability under Credit Agreement		62,511			112,136
Less—Deferred tax asset on derivative instruments and asset retirement obligation		(24,056	)		(847	)
Less—Short-term derivative instruments		(1,016	)		(7,599	)
Current assets as adjusted	$	114,694		$	195,553
Current liabilities per GAAP	$	119,292		$	104,255
Less—Short-term derivative instruments		(63,125	)		(12,376	)
Less—Short-term asset retirement obligation		(346	)		(749	)
Current liabilities as adjusted	$	55,821		$	91,130
Current ratio for loan compliance		2.05			2.15

On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement provided for a $750.0 million maximum commitment amount, is secured by our oil and gas properties and matures on October 31, 2010. Obligations under the Credit Agreement are also secured by pledges by us and each of the borrowers of equity interests in other subsidiaries owned by us and them, excluding specified entities. Availability under our Credit Agreement is subject to a borrowing base, which initially was $750.0 million and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. As a result of the issuance of our 8 ⁷/8% Senior Notes on January 18, 2007, our maximum commitment amount and borrowing base were adjusted to $652.0 million and $500 million, respectively. As of March 16, 2007, we had $342.0 million outstanding under our Credit Agreement.

If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At December 31, 2006, $634.0 million of our borrowings were Eurodollar loans and $3.0 million were Alternate Base Rate loans. Effective January 3, 2007, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.50% depending on the utilization percentage of the conforming borrowing base. At December 31, 2006, the LIBOR rate was 5.33%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.21% resulting in an effective interest rate of 7.54% 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.

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Interest on the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus 1/2 of 1%; plus a margin where the margin varies from 0.00% to 1.00% depending on the utilization percentage of the borrowing base. At December 31, 2006 the applicable rate was 8.25% and the applicable margin was 0.50% resulting in an effective interest rate of 8.75% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

Commitment fees of 0.25% to 0.50% accrue on the unused portion of the borrowing base amount, depending on the utilization percentage, and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

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

• incur additional indebtedness;

• create or incur additional liens on our oil and gas properties;

• pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;

• make investments in or loans to others;

• change our line of business;

• enter into operating leases;

• merge or consolidate with another person, or lease or sell all or substantially all of our assets;

• sell, farm-out or otherwise transfer property containing proved reserves;

• enter into transactions with affiliates;

• issue preferred stock;

• enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;

• enter into certain swap agreements; and

• amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.

The Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0 and a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Credit Agreement, of not greater than:

• 5.00 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007;

• 4.75 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on June 30, 2007;

• 4.50 to 1.0 for the annualized period commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on September 30, 2007;

• 4.25 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2007; and

• 4.00 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2008 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter thereafter.

The Credit Agreement also specifies events of default, including:

• our failure to pay principal or interest under the Credit Agreement when due and payable;

• our representations or warranties proving to be incorrect, in any material respect, when made or deemed made;

• our failure to observe or perform certain covenants, conditions or agreements under the Credit Agreement;

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• our failure to make payments on certain other material indebtedness when due and payable;

• the occurrence of any event or condition that requires the redemption or repayment of, or an offer to redeem or repay, certain other material indebtedness prior to its scheduled maturity;

• the commencement of an involuntary proceeding seeking liquidation, reorganization or other relief, or the appointment of a receiver, trustee, custodian or other similar official for us or our subsidiaries, and the proceeding or petition continues undismissed for 60 days or an order approving the foregoing is entered;

• our inability, admission or failure generally to pay our debts as they become due;

• the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million;

• a Change of Control (as defined in the Credit Agreement); and

• the occurrence of a default under any permitted bond document, which such default continues unremedied or is not waived prior to the expiration of any applicable grace or cure under any permitted bond document.

Our 8 ¹/2% Senior Notes due 2015. On December 1, 2005, we issued $325.0 million aggregate principal amount of 8 ¹/2% Senior Notes maturing on December 1, 2015. 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, as defined in the indenture.

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.

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If we experience a change of control (as defined in the indenture governing the 8 ¹/2% Senior Notes), including making certain asset sales, 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.

Our 8 ⁷/8% Senior Notes due 2017. On January 18, 2007, we issued $325.0 million aggregate principal amount of 8 ⁷/8% Senior Notes maturing on February 1, 2017. The 8 ⁷/8% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, including our existing 8  ¹/2% Senior Notes, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 ⁷/8% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries, as defined in the indenture.

On and after February 1, 2012, we may redeem some or all of the 8 ⁷/8% 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 February 1, 2010, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 ⁷/8% Senior Notes from the proceeds, so long as:

• we pay to the holders of such notes a redemption price of 108.875% of the principal amount of the 8 ⁷/8% Senior Notes, plus accrued and unpaid interest to the date of redemption; and

• at least 65% of the aggregate principal amount of the 8 ⁷/8% Senior Notes remains outstanding after each such redemption, other than 8 ⁷/8% Senior Notes held by us or our affiliates.

Finally, prior to February 1, 2012, 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 ⁷/8% 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 ⁷/8% Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the 8 ⁷/8% Senior Notes the opportunity to sell to us their 8 ⁷/8% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

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

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Contractual obligations. The following table summarizes our contractual obligations and commitments as of December 31, 2006:

(Dollars in thousands)(1)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:
Revolving credit line—including estimated interest expense	$	47,020	$	731,040	$	—	$	—	$	778,060
Senior notes, including estimated interest expense		27,625		82,875		82,875		380,250		573,625
Other long-term notes—including estimated interest expense		4,299		11,063		1,046		178		16,586
Capital leases—including estimated interest		176		171		—		—		347
Operating leases		595		282		—		—		877
Abandonment obligations		749		2,247		2,247		22,883		28,126
Derivative obligations		12,376		627		866		—		13,869
Drilling obligation		1,897		—		—		—		1,897
Preferential purchase right		5,005		—		—		—		5,005
Total	$	99,742	$	828,305	$	87,034	$	403,311	$	1,418,392

(1) As of December 31, 2006, the Company has no off-balance sheet arrangements.

We entered into an agreement to build a natural gas pipeline, a CO₂ pipeline and compression facilities at an ethanol plant expected to be constructed and operational in 2007. The construction of these pipelines and facilities and the related costs are contingent on certain events and are currently estimated to be a minimum of $2.2 million. We also have a long-term contract to purchase all of the CO₂ manufactured at the ethanol plant, if built. Based on estimated plant capacity, it is estimated that we will purchase approximately 4.2 Mmcf per day at variable contract prices over the ten-year contract term with the possibility of renewal.

We have two additional long-term contracts that require us to purchase CO₂ for tertiary recovery projects. Under one contract we may purchase a variable amount of CO₂, up to 20.0 MMcf per day through July 1, 2010. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 12 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, which is consistent with our current level. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

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.

Derivative Instruments. Certain of our crude oil and natural gas derivative contracts are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity”, as amended, or SFAS 133. This policy significantly impacts the timing of revenue or expense recognized from this activity as our contracts are adjusted to their fair value at the end of each month. Pursuant to SFAS 133, the effective portion of the hedge gain or loss, meaning that the change in the fair value of the contract offsets the changes in the expected future cash flows from our forecasted production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “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 stockholders’ equity. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) on oil and gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment are marked to their period end market values with changes reported in earnings, and our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments.

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.

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• 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 report is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 85% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2006 and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

• 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.

• 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. 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 future development costs and abandonment costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

In accordance with Statement on Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”, we record a liability for the discounted fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. The present value calculation requires us to make numerous assumptions and judgments, including the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, 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.

45

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

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

Recent accounting pronouncements

In June 2006, the FASB issued interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have evaluated the impact of FIN 48 as of the January 1, 2007 adoption date and believe there will be no material impact to our financial statements.

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

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

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

46

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our year ended December 31, 2006 production, our gross revenues from oil and gas sales would change approximately $2.1 million for each $0.10 change in gas prices and $1.9 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into swap agreements. For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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

47

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

	Natural Gas basis protection swaps			Natural Gas Swaps					Crude Oil Swaps
	Non-hedge			Hedge					Hedge			Non-hedge
	Volume MMcf	Weighted average fixed price to be received		Volume MMcf	Weighted average fixed price to be received		Percent of PDP production hedged(1)		Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average fixed price to be received		Percent of PDP production(1)(2)
1Q 2007	2,400	$	0.96	3,310	$	8.36	58.0	%	636	$	58.14	—		—	78.7	%
2Q 2007	2,370		0.77	3,210		7.02	59.0	%	627		58.21	—		—	79.1	%
3Q 2007	2,520		0.79	3,210		7.03	61.5	%	606		60.03	—		—	78.3	%
4Q 2007	2,220		1.02	2,910		8.12	57.8	%	576		63.11	—		—	76.2	%
1Q 2008	2,070		1.16	960		10.07	20.0	%	507		67.34	60	$	67.48	79.6	%
2Q 2008	2,220		0.81	870		8.10	19.2	%	477		67.21	60		67.63	79.8	%
3Q 2008	2,220		0.81	610		8.14	13.9	%	472		67.48	60		67.64	80.4	%
4Q 2008	2,120		0.90	450		8.72	10.6	%	436		68.07	74		67.41	78.5	%
1Q 2009	2,070		0.92	—		—	—		375		67.33	111		67.15	80.3	%
2Q 2009	540		0.82	—		—	—		375		66.95	90		66.94	78.0	%
3Q 2009	—		—	—		—	—		375		66.53	90		66.57	79.2	%
4Q 2009	—		—	—		—	—		375		66.15	90		66.24	80.4	%
1Q 2010	—		—	—		—	—		339		65.79	102		65.80	79.1	%
2Q 2010	—		—	—		—	—		339		65.50	90		65.47	77.9	%
3Q 2010	—		—	—		—	—		339		65.04	90		65.10	79.5	%
4Q 2010	—		—	—		—	—		339		64.67	90		64.75	80.4	%
1Q 2011	—		—	—		—	—		309		64.40	99		64.16	79.4	%
2Q 2011	—		—	—		—	—		309		64.06	90		63.90	78.6	%
3Q 2011	—		—	—		—	—		309		63.71	90		63.64	79.8	%
4Q 2011	—		—	—		—	—		309		63.33	90		63.39	80.7	%

(1) Based on our most recent internally estimated PDP production for such periods.

(2) Percentage includes both hedge and non-hedge swaps.

Subsequent to December 31, 2006, we entered into additional natural gas swaps for 3,600 MMcf for the periods of February 2007 through December 2007 at a weighted average price of $6.95.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of December 31, 2006 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $750.0 million, equal to our borrowing base at December 31, 2006, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $7.5 million.

48

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to financial statements

	Page
Chaparral Energy, Inc. consolidated financial statements:
Report of independent registered public accounting firm	50
Consolidated balance sheets as of December 31, 2005 and 2006	51
Consolidated statements of income for the years ended December 31, 2004, 2005 and 2006	52
Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2004, 2005 and 2006	53
Consolidated statements of cash flows for the years ended December 31, 2004, 2005 and 2006	54
Notes to consolidated financial statements	56

49

Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and subsidiaries as of December 31, 2005 and 2006, and the related consolidated statements of income, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries as of December 31, 2005 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

March 29, 2007

50

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

(dollars in thousands, except share data)	December 31,
	2005			2006
Assets
Current assets:
Cash and cash equivalents	$	1,598		$	8,803
Accounts receivable, net		42,431			62,728
Inventories		6,788			7,505
Deferred income taxes		23,831			968
Prepaid expenses		1,591			4,260
Derivative instruments		1,016			7,599
Total current assets		77,255			91,863
Property and equipment—at cost, net		22,428			31,809
Oil & gas properties, using the full cost method:
Proved		600,185			1,254,230
Unproved		10,150			18,299
Accumulated depletion and depreciation		(74,799	)		(121,859	)
Total oil & gas properties		535,536			1,150,670
Funds held in escrow		—			23,385
Other assets		12,160			33,708
	$	647,379		$	1,331,435
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	44,183		$	71,075
Revenue distribution payable		8,858			17,249
Current maturities of long-term debt and capital leases		3,126			3,555
Derivative instruments		63,125			12,376
Total current liabilities		119,292			104,255
Long-term debt and capital leases, less current maturities		118,418			647,717
8 1/2% Senior Notes, due 2015		325,000			325,000
Derivative instruments		32,001			2,300
Deferred compensation		645			771
Asset retirement obligations		15,450			27,377
Deferred income taxes		26,406			46,151
Commitments and contingencies (note 13)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 775,000 and 877,000 shares issued and outstanding as of December 31, 2005 and 2006, respectively		8			9
Additional paid in capital		—			100,918
Retained earnings		58,126			80,883
Accumulated other comprehensive loss, net of taxes		(47,967	)		(3,946	)
		10,167			177,864
	$	647,379		$	1,331,435

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

51

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of income

	Year Ended December 31,
(dollars in thousands, except share and per share amounts)	2004			2005			2006
Revenues:
Oil and gas sales	$	113,546		$	201,410		$	249,180
Loss from oil and gas hedging activities		(21,350	)		(68,324	)		(4,166	)
Total revenues		92,196			133,086			245,014
Costs and expenses:
Lease operating		26,928			42,147			71,663
Production tax		8,272			14,626			18,710
Depreciation, depletion and amortization		17,533			31,423			52,299
General and administrative		5,985			9,808			14,659
Total costs and expenses		58,718			98,004			157,331
Operating income		33,478			35,082			87,683
Non-operating income (expense):
Interest expense		(6,162	)		(15,588	)		(45,246	)
Non-hedge derivative losses		—			—			(4,677	)
Other income		279			665			792
Net non-operating expense		(5,883	)		(14,923	)		(49,131	)
Income before income taxes and minority interest		27,595			20,159			38,552
Income tax expense		9,880			7,309			14,817
Minority interest		—			—			(71	)
Net income	$	17,715		$	12,850		$	23,806
Net income per share (basic and diluted)	$	22.86		$	16.58		$	29.74
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			775,000			800,500

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

52

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

and comprehensive income (loss)

(dollars in thousands)	Members’ units/ Common Stock
	Units/Shares		Amount		Additional Paid In Capital		Undistributed/ Retained earnings			Accumulated other comprehensive income (loss)			Total
Balance at January 1, 2004	50,000,000		$	1	$	—	$	30,977		$	(4,900	)	$	26,078
Net income	—			—		—		17,715			—			17,715
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $12,766	—			—		—		—			(20,152	)		(20,152	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $7,801	—			—		—		—			12,945			12,945
Total comprehensive income														10,508
Balance at December 31, 2004	50,000,000			1		—		48,692			(12,107	)		36,586
Conversion from LLC to C Corporation	(49,225,000	)		7		—		(7	)		—			—
Dividends	—			—		—		(3,409	)		—			(3,409	)
Net income	—			—		—		12,850			—			12,850
Other comprehensive loss, net
Unrealized loss on hedges, net of taxes of $42,970	—			—		—		—			(68,749	)		(68,749	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $20,695	—			—		—		—			32,889			32,889
Total comprehensive loss														(23,010	)
Balance at December 31, 2005	775,000			8		—		58,126			(47,967	)		10,167
Issuance of common stock	102,000			1		100,918		—			—			100,919
Dividends	—			—		—		(1,049	)		—			(1,049	)
Net income	—			—		—		23,806			—			23,806
Other comprehensive income, net
Unrealized gain on hedges, net of taxes of $18,916	—			—		—		—			29,949			29,949
Reclassification adjustment for hedge losses included in net income, net of taxes of $8,855	—			—		—		—			14,072			14,072
Total comprehensive income														67,827
Balance at December 31, 2006	877,000		$	9	$	100,918	$	80,883		$	(3,946	)	$	177,864

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

53

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Year Ended December 31,
(dollars in thousands)	2004			2005			2006
Cash flows from operating activities
Net income	$	17,715		$	12,850		$	23,806
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		17,533			31,423			52,299
Deferred income taxes		9,693			7,637			14,839
Unrealized (gain) loss on ineffective portion of hedges		604			14,740			(18,761	)
Non-cash change in fair value of derivative instruments		—			—			4,681
(Gain) loss on sale of assets		97			(231	)		(132	)
Other		222			687			1,277
Change in assets & liabilities, net of assets and liabilities of business acquired
Accounts receivable		278			(7,979	)		(13,213	)
Inventories		(1,402	)		(2,961	)		(329	)
Prepaid expenses and other assets		(834	)		(270	)		376
Accounts payable and accrued liabilities		2,963			4,784			16,659
Revenue distribution payable		1			(4,936	)		7,696
Net cash provided by operating activities		46,870			55,744			89,198
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(94,947	)		(170,570	)		(201,300	)
Acquisition of a business, net of cash acquired		—			(113,622	)		(466,656	)
Payment on non-hedge derivative transactions assumed in acquisition of a business		—			(42,108	)		—
Cash in escrow		—			—			(21,795	)
Proceeds from dispositions of property and equipment and oil and gas properties		2,726			1,202			5,820
Purchase of prepaid production tax asset		—			—			(15,000	)
Other		80			30			(4,917	)
Net cash used in investing activities		(92,141	)		(325,068	)		(703,848	)
Cash flows from financing activities
Proceeds from long-term debt		58,358			122,676			629,936
Repayment of long-term debt and acquisition financing		(2,431	)		(309,383	)		(100,199	)
Proceeds from equity issuance		—			—			100,919
Proceeds from acquisition financing		—			132,000			—
Proceeds from senior notes		—			325,000			—
Principal payments under capital lease obligations		(807	)		(442	)		(148	)
Repayments of notes payable to members		(1,059	)		—			—
Dividends		—			(3,409	)		(1,049	)
Settlement of derivative instruments acquired		—			—			876
Fees paid related to financing activities		—			(9,195	)		(8,107	)
Fees paid related to IPO activities		—			(167	)		(373	)
Net cash provided by financing activities		54,061			257,080			621,855
Net increase (decrease) in cash and cash equivalents		8,790			(12,244	)		7,205
Cash and cash equivalents at beginning of period		5,052			13,842			1,598
Cash and cash equivalents at end of period	$	13,842		$	1,598		$	8,803
Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	5,524		$	12,590		$	44,068
Income taxes		17			(328	)		(22	)

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

54

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows — (continued)

Supplemental disclosure of noncash investing and financing activities

During the year ended December 31, 2004, the Company entered into capital leases for the purchase of machinery and equipment of $82 and purchased two licenses for seismic data by incurring long-term obligations of $4,096. During the year ended December 31, 2005, the Company entered into capital lease obligations of $70 for the purchase of machinery and equipment. During the year ended December 31, 2006, the Company entered into capital lease obligations of $140 for the purchase of machinery and equipment.

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

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

Interest of $107 and $3 was capitalized during the years ended December 31, 2004 and 2005, respectively, primarily related to the construction of the Company’s office building and other construction projects. Interest of $1,001 was capitalized during the year ended December 31, 2006, primarily related to the acquisition of unproved oil and gas leaseholds.

55

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(Dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and subsidiaries, (collectively, “we”, “our”, “us” or the “Company”) is involved in the acquisition, exploration, development, production and operation of oil and gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana and Wyoming.

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

Principles of consolidation

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

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

Reclassifications

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

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and gas reserves, deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

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, 2005 and 2006 were $694 and $1,034, respectively. The Company determines its allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and gas properties operated by the Company and the owner’s ability to pay its obligation, among other things.

The Company writes off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2004, 2005, and 2006 was $248, $140, and $553, respectively. Interest accrues beginning on the day after the due date of the receivable. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against current interest income. Accounts receivable consisted of the following at December 31:

	2005			2006
Joint interests	$	14,682		$	13,771
Accrued oil and gas sales		27,075			32,763
Receivable from purchase price adjustment		—			14,406
Other		912			2,084
Allowance for doubtful accounts		(238	)		(296	)
	$	42,431		$	62,728

56

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Inventories

Inventories consist of equipment used in developing oil and gas properties of $5,029 and $4,832 at December 31, 2005 and 2006, respectively, and product of $1,759 and $2,673 at December 31, 2005 and 2006, respectively. Equipment inventory is carried at the lower of cost or market using the specific identification method. Product inventories are stated at the lower of production cost or market.

Property and equipment

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

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

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

Oil and gas properties

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

Depreciation, depletion and amortization of oil and gas properties are provided using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs and the anticipated proceeds from salvaging equipment. Depreciation, depletion and amortization expense of oil and gas properties was $14,596, $27,650, and $47,086 for the years ended December 31, 2004, 2005, and 2006, respectively.

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.

Production tax benefit asset

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

Funds held in escrow

The Company has funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following at December 31:

	2006
Title defect escrow from acquisition	$	21,795
Plugging and abandonment escrow		1,590
	$	23,385

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

57

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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

Impairment of long-lived assets

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

Deferred income taxes

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

Revenue recognition

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

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. The Company recognizes gas imbalances on the sales method and, accordingly, has recognized revenue on all production delivered to its purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for the Company’s obligation for natural gas taken by its purchasers which exceeds the Company’s ownership interest of the well’s total production. The Company’s aggregate imbalance due to over production is approximately 1,027,000 thousand cubic feet (mcf), 1,866,000 mcf, and 1,903,000 mcf at December 31, 2004, 2005, and 2006, respectively. The Company’s aggregate imbalance due to under production is approximately 1,508,000 mcf, 3,313,000 mcf, and 3,331,000 mcf at December 31, 2004, 2005, and 2006, respectively.

Derivative transactions

The Company uses price swaps to reduce the effect of fluctuations in crude oil and natural gas prices. The Company accounts for these transactions in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 requires that the Company recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation. Derivatives that are not hedges must be adjusted to fair value through income.

If the derivative qualifies as a hedge, depending on the nature of the hedge, changes in the fair value of the derivative will be offset against the change in fair value of the hedged assets, liabilities or firm commitments through income, or will be recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, will be immediately recognized in income. If it is probable the oil or gas sales which are hedged will not occur or the hedge is not highly effective, hedge accounting is discontinued and the effect is immediately recognized in income.

Under SFAS No. 133, if a derivative which qualified for cash flow hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination would remain in accumulated other comprehensive income (loss) and would be amortized into oil and gas sales over the original term of the instrument. No derivatives were liquidated or sold prior to maturity during 2004, 2005, or 2006. The ineffective portions of derivative gains or losses are reported in loss from oil and gas hedging activities on the consolidated statements of income.

58

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Asset retirement obligations

The Company accounts for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of income. The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses on its oil and gas properties and related facilities disposal. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules.

Environmental 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, 2005 and 2006, the Company has not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon financial position, operating results, or the cash flows of the Company. As of December 31, 2006, the Company has accrued a liability for site restoration costs of $1,600 related to properties acquired in 2006. The liability is included in accounts payable and accrued liabilities in the consolidated balance sheets.

Earnings per share

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

Recently issued accounting standards

In June 2006, the FASB issued interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company has evaluated the impact of FIN 48 as of the January 1, 2007 adoption date and believes there will be no material impact to its financial statements.

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

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

In February 2007, the FASB issued SFAS No. 159, which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company is currently evaluating the impact that SFAS No. 159 will have on its consolidated financial statements.

59

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Note 2: Significant acquisitions

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

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

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

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

CEI-Bristol—On September 30, 2005, the Company acquired the 99% limited partner interest in CEI Bristol Acquisition, L.P., or CEI Bristol, from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. CEI Bristol owns properties primarily located in the Mid-Continent area of Oklahoma and Permian Basin areas of West Texas. As a result of the acquisition, the Company expects to increase production in 2006.

Prior to the acquisition, the Company held a 1% general partner interest through its wholly-owned subsidiary Chaparral Oil, L.L.C. The Company accounted for its investment in CEI Bristol under the equity method. The investment was $741 as of December 31, 2004 and is included in other assets. As a result of the acquisition, CEI Bristol became one of the Company’s wholly-owned subsidiaries and its results have been included in the consolidated statement of income from that date. Total consideration paid by the Company was approximately $158,108, subject to certain purchase price adjustments. The acquisition cost was funded with proceeds from a $132,000 bridge loan facility with General Electric Capital Corporation, borrowings from the Company’s revolving line of credit and cash on hand. As part of the acquisition, the Company acquired derivative liabilities of $42,108 that were not designated as hedges and were settled on October 3, 2005.

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

	Calumet(1)			CEI-Bristol
Calculation and allocation of purchase price:
Cash payment	$	500,000		$	158,108
Working capital receivable due from Calumet owners		(14,406	)		—
Title defect escrow		(21,795	)		—
Total purchase price		463,799			158,108
Plus fair value of liabilities assumed:
Accounts payable and accrued expenses		12,033			4,371
Derivative liabilities		838			42,108
Asset retirement obligations		9,342			1,721
Total purchase price plus liabilities assumed	$	486,012		$	206,308
Fair value of assets acquired:
Current assets, including cash of $5,968 and $44,486, respectively	$	14,560		$	53,363
Oil and gas properties		464,860			152,945
Property and equipment		5,010			—
Restricted cash		1,582			—
Total fair value of assets acquired	$	486,012		$	206,308

(1) The purchase allocation of the Calumet acquisition is preliminary and subject to additional adjustments. The Company expects to complete the final allocation in the next 10 months.

The unaudited pro forma information of the Company set forth below includes the operations of Chaparral and CEI Bristol for the years ended December 31, 2004 and 2005 as if the acquisition occurred on January 1, 2004, and the operations of Chaparral and Calumet for the years ending December 31, 2005 and 2006 as if the acquisition occurred on January 1, 2005. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

(dollars in thousands, except per share data)	Year ended December 31, 2004				Year ended December 31, 2005				Year ended December 31, 2006
	As reported		Pro forma		As reported		Pro forma		As reported		Pro forma
Revenue	$	92,196	$	125,614	$	133,086	$	248,343	$	245,014	$	327,144
Net income	$	17,715	$	20,166	$	12,850	$	3,577	$	23,806	$	19,226
Net income per share (basic and diluted)	$	22.86	$	26.02	$	16.58	$	4.62	$	29.74	$	24.02

60

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Note 3: Property and equipment

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

	2005		2006
Furniture and fixtures	$	974	$	1,132
Automobiles and trucks		5,544		8,807
Machinery and equipment		7,832		11,288
Office and computer equipment		4,216		5,303
Building and improvements		11,471		12,074
		30,037		38,604
Less accumulated depreciation and amortization		8,745		10,813
		21,292		27,791
Work in progress		—		1,446
Land		1,136		2,572
	$	22,428	$	31,809

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

	2005		2006
Office and computer equipment	$	1,785	$	1,762
Machinery and equipment		82		82
		1,867		1,844
Less accumulated depreciation and amortization		1,024		1,312
	$	843	$	532

Note 4: Derivative activities and financial instruments

Derivative activities

The Company’s results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of and demand for oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, the Company enters into swap agreements. For swap instruments, the Company receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

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

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

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

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

61

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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

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

	December 31,
	2005			2006
Derivative assets (liabilities):
Gas swaps	$	(60,158	)	$	10,118
Oil swaps		(33,952	)		(16,349	)
Natural gas basis differential swaps		—			(846	)
	$	(94,110	)	$	(7,077	)

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

	Year ended December 31,
	2004			2005			2006
Reclassification of settled contracts	$	(20,746	)	$	(53,584	)	$	(22,927	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		(604	)		(14,740	)		18,761
	$	(21,350	)	$	(68,324	)	$	(4,166	)

Based upon market prices at December 31, 2006 the Company expects to charge $2,703 of the balance in accumulated other comprehensive loss to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of December 31, 2006 are expected to be settled by December 2011.

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

	Year Ended December 31, 2006
Unrealized loss on natural gas basis differential hedges	$	931
Unrealized loss on non-qualified derivative contracts		3,746
	$	4,677

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

62

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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, 2005 and 2006 approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2006, the carrying value of the 8 ¹/2 Senior Notes due 2015 approximates fair value.

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

Concentration of Credit Risk

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

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

Note 5: Asset retirement obligations

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

	As of December 31,
	2005			2006
Beginning balance	$	10,324		$	15,796
Liabilities incurred in current period		1,094			715
Liabilities acquired (see Note 2)		1,721			9,342
Liabilities settled in current period		(264	)		(256	)
Accretion expense		1,056			1,773
Revisions of estimated cash flows		1,865			756
Ending ARO balance		15,796			28,126
Less current portion		346			749
	$	15,450		$	27,377

63

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Note 6: Long-term debt

Long-term debt consists of the following:

	December 31,
	2005		2006
Revolving credit line with banks(1)	$	109,000	$	637,000
Real estate mortgage note, payable in monthly installments of $65, bearing interest at LIBOR plus 2.66% (effective rate of 5.79% and 7.77% at December 31, 2005 and 2006, respectively), due August 31, 2010; collateralized by real property		6,212		6,314
Real estate mortgage notes, payable in monthly installments of $3, bearing interest at defined bank base rate plus 1% (effective rate of 7% at December 31, 2005 and 2006), adjusted and fixed every five years with a floor rate of 7%, due January and May 2017; collateralized by real property		330		309
Real estate mortgage notes, payable in monthly installments of $2, bearing interest at 6.95% until August 2009; interest rate adjusted to the 3 year Treasury Index on August 2009 and every 36 months thereafter; due August 2021; collateralized by real property		—		213
Real estate mortgage note, payable in monthly installments of $2, bearing interest at 6.53%; balloon payment of unpaid balance due February 2011; collateralized by real property		—		200
Real estate mortgage note, interest only monthly payments beginning August 5, 2005 at 6.04% with lump sum principal payment due at maturity, July 5, 2006; collateralized by real property		400		—
Installment note payable to bank, payable in monthly installments of $3, bearing interest at 8%, due July 15, 2006; collateralized by real property		22		—
Installment note payable, principal and interest payable quarterly in varying amounts, noninterest-bearing (discounted at 5.6% at December 31, 2005 and 2006), due December 2007		847		435
Installment note payable, principal and interest payable in annual installments of $550, noninterest-bearing (discounted at 5.6% at December 31, 2005 and 2006), due September 2007		895		402
Non-Interest bearing forgivable government loan(2)		—		250
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.62% to 9.055%, due January 2006 through December 2011; collateralized by automobiles, machinery and equipment		3,501		5,821
		121,207		650,944
Less current maturities		2,991		3,392
	$	118,216	$	647,552

(1) In 2005, the Company entered into a Sixth Restated Credit Agreement, which provides for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base has been determined based on reserve value, among other factors. Under the Sixth Restated Credit Agreement, the borrowing base was $172,500 at December 31, 2005, matured in June 2009 and interest was paid at least every three months on $94,000 and $15,000 based upon various LIBOR options as of December 31, 2005 (effective rate of 5.94% and 5.88%, respectively). Effective May 25, 2006, the borrowing base was adjusted to $200,000. Effective September 11, 2006, the borrowing base was adjusted to $250,000. In October 2006, the Company entered into a Seventh Restated Credit Agreement, which provided for a $750,000 maximum commitment amount and a conforming borrowing base of $650,000. The borrowing and conforming borrowing base have scheduled reductions down to $610,000 on May 1, 2007. The Seventh Restated Credit Agreement matures on October 31, 2010. Interest is paid at least every three months on $634,000 based upon LIBOR and $3,000 based on an Alternative Base Rate, as defined in the credit agreement as of December 31, 2006 (effective rate of 7.375% and 8.750%, respectively). The credit line is collateralized by the Company’s oil and gas properties. 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, 2006. As a result of the issuance of our 8 ⁷/8% Senior Notes on January 18, 2007, our maximum commitment amount and borrowing base were adjusted to $652,000 and $500,000, respectively.

(2) A local economic development authority has issued a non-interest bearing note payable to Oklahoma Ethanol, L.L.C., a 67% owned subsidiary of the Company, as incentive for the construction and operation of an ethanol plant. The note bears no interest and matures June 2012. The economic development authority will forgive payment of the note upon its maturity if certain requirements are met by June 2009 and maintained for three subsequent years, as set forth by the agreement.

64

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Maturities of long-term debt as of December 31, 2006 are as follows:

2007	$	3,392
2008		2,166
2009		638,364
2010		5,910
2011		523
2012 and thereafter		589
	$	650,944

Note 7: Capital leases

Future minimum lease payments under capital leases for property and equipment and the present value of the net minimum lease payments as of December 31, 2006 are as follows:

2007	$	176
2008		153
2009		18
Total minimum lease payments		347
Less amount representing interest		19
Present value of net minimum lease payments		328
Less current portion		163
	$	165

Note 8: Issuance of 8 ¹/2% Senior Notes, due 2015

On December 1, 2005, the Company issued $325,000 of 8.5% senior notes due 2015 at a price of 100% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to repay the $132,000 bridge loan facility with General Electric Capital Corporation and to pay down debt under our revolving credit line.

Interest is payable on the senior notes semi-annually on June 1 and December 1 each year beginning June 1, 2006. The senior notes mature on December 1, 2015. On or after December 1, 2010, the Company, at its option, may redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.25% after December 1, 2010, 102.83% after December 1, 2011, 101.42% after December 31, 2012, and 100% after December 1, 2013 and thereafter. Prior to December 1, 2008, the Company may redeem up to 35% of the senior notes with the net proceeds of one or more equity offerings at a redemption price of 108.5%, plus accrued and unpaid interest.

65

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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

• incur or guarantee additional debt and issue certain types of preferred stock;

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

• make investments;

• create liens on assets;

• create restrictions on the ability of restricted subsidiaries to pay dividends or make other payments to us;

• transfer or sell assets;

• engage in transactions with affiliates;

• consolidate, merge or transfer all or substantially all assets and the assets of subsidiaries; and

• enter into other lines of business.

In connection with the issuance of the senior notes, the Company capitalized $9,251 of costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized costs of $9,147 and $8,604 as of December 31, 2005 and 2006, respectively, that are included in other assets. Amortization of $48 and $598 was charged to interest expense during the years ended December 31, 2005 and 2006, respectively, related to these costs.

Chaparral is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries. Oklahoma Ethanol, a 66.67% owned subsidiary, has no significant operations or capitalization and is not a restricted subsidiary or guarantor of the notes.

Note 9: Income taxes

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

	2004		2005			2006
Current tax expense (benefit)	$	5	$	(328	)	$	(22	)
Deferred tax expense		9,875		7,637			14,839
	$	9,880	$	7,309		$	14,817

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

	2004		2005		2006
Statutory rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	2.6	%	3.6	%	3.6	%
Statutory depletion	(0.2	)%	(1.0	)%	(0.5	)%
Other	(1.6	)%	(1.3	)%	0.3	%
Effective tax rate	35.8	%	36.3	%	38.4	%

66

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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

	2005			2006
Deferred tax assets related to
Derivative instruments	$	36,391		$	2,489
Asset retirement obligations		1,038			2,035
Accrued expenses, allowance and other		698			1,619
Net operating loss carryforwards
Federal		8,195			12,159
State		4,928			7,194
Statutory depletion carryforwards		1,175			1,387
Alternative minimum tax credit carryforwards		204			204
		52,629			27,087
Less: valuation allowance		3,289			4,675
		49,340			22,412
Deferred tax liabilities related to
Derivative instruments		—			(1,113	)
Property and equipment		(51,248	)		(65,448	)
Inventories		(667	)		(1,034	)
		(51,915	)		(67,595	)
Net deferred tax liabilities	$	(2,575	)	$	(45,183	)

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

The Company has federal net operating loss carryforwards of approximately $35,000 at December 31, 2006, which will begin to expire in 2008 if unused. At December 31, 2006, the Company has state net operating loss carryforwards of approximately $127,000, which will begin to expire in 2007. At December 31, 2006, approximately $83,000 of the state net operating loss carryforwards have been reduced by a valuation allowance based on the Company’s assessment that it is more likely than not that a portion will not be realized. In addition, at December 31, 2006, the Company had tax percentage depletion carryforwards of approximately $3,964 which are not subject to expiration.

Note 10: Related party transactions

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

Prior to the September 30, 2005 acquisition of the 99% limited partner’s interest, the Company managed, administered and operated the properties and business and affairs of CEI Bristol. The Company acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were $1,018 for the year ended December 31, 2004 and $735 for the nine months ended September 30, 2005. Additionally, the Company was compensated for management services provided to CEI Bristol through a management fee. Management fees earned by the Company were $228 for the year ended December 31, 2004 and $111 for the nine months ended September 30, 2005.

67

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

On December 28, 2005, the Company’s chief executive officer acquired the Company’s beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112 in cash together with the assumption of a loan of $262, which represents the Company’s net book value and its estimated current fair market value. The house was acquired by the Company in April 2004 for the purchase price of $328. Record title was taken in the name of the Company’s chief executive officer, who entered into a mortgage securing the loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral used the house, the Company’s board of directors approved the payment by the Company of the downpayment on the house and the principal and interest payments on the loan. The Company made monthly payments of principal and interest totaling approximately $38 through November 2005.

Note 11: 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. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Payment is not required by the participant upon redemption.

Prior to January 1, 2006, the Company accounted for our deferred compensation plans under the recognition and measurement provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations, which requires that this award be measured at the end of each period based on the current calculated fair value of the award. As prescribed by the Plan, fair market value is calculated based on the Company’s total asset value less total liabilities, with both assets and liabilities being adjusted to fair value. The primary adjustment required is the adjustment of oil and gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips.

Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS No. 123(R), using the modified-prospective transition method. Under that transition method, compensation cost recognized in 2006 includes compensation costs for all phantom units granted prior to, but not yet vested as of January 1, 2006 and phantom units granted subsequent to January 1, 2006, based on the fair value estimated in accordance with SFAS No. 123(R). Since the phantom units are liability awards, fair value of the units is remeasured at the end of each reporting period until settlement. Prior to the settlement, the cost is recognized proportionately over the employees’ requisite service period, and once that period is over and the awards are fully vested, participants are paid the value of their phantom units in cash immediately. Results for prior periods have not been restated and the Company had no cumulative effect adjustment upon adoption of SFAS No. 123(R) under the modified-prospective method.

Prior to the adoption of SFAS No. FAS123(R), the Company presented all tax benefits of deductions resulting from the phantom unit plan as operating cash flows in the Consolidated Statement of Cash Flows. SFAS No. 123(R) requires the cash flows resulting from tax benefits of tax deductions in excess of the compensation cost recognized (excess tax benefits) to be classified as financing cash flows.

Compensation expense is recognized over the vesting period of the phantom units and is reflected in general and administrative expenses in the income statement. Such expense is calculated net of forfeitures estimated based on the Company’s historical and expected turnover rates. The Company recognized deferred compensation expense of $120, $525 and $128 for the years ended December 31, 2004, 2005 and 2006, respectively.

68

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

A summary of the Company’s phantom unit activity as of December 31, 2005, and changes during the year ended December 31, 2006 is presented in the following table:

	Fair Value		Phantom Units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per share)
Unvested and total outstanding at December 31, 2005	$	17.89	164,906
Granted	$	17.89	21,357
Vested	$	17.89	(52	)
Forfeited	$	17.89	(26,173	)
Unvested and total outstanding at December 31, 2006	$	14.29	160,038		4.66	$	2,287

Upon vesting, the Company is required to redeem all units. Accordingly, the contract term and the vesting period are the same. There are no vested units as of December 31, 2006.

The fair value of each unit award is estimated on the date of grant using the Black-Scholes option pricing model, which uses the assumptions in the following table:

	Year ended December 31, 2006
Dividend yield	0.0	%
Volatility	75.0	%
Risk-free interest rate	4.7	%
Expected life (in years)	4.00-6.00

The Company estimated volatility based on an average of the volatilities of similar public entities whose share prices are publicly available over the expected life of the granted units. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected term of the option. The expected dividend yield is based on the Company’s current dividend yield and the best estimate of projected dividend yield for future periods within the expected life of the option.

As of December 31, 2006, there was approximately $1,514 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 4.66 years.

Note 12: 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, 2004, 2005 and 2006, there were 207, 256 and 415 employees, respectively, participating in the plan. Contributions recognized by the Company totalled $544, $682 and $883 for the years ended December 31, 2004, 2005 and 2006, respectively.

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

The Company has entered into operating lease agreements for the use of office space and equipment rental on oil and gas properties. Rent expense for the years ended December 31, 2004, 2005, and 2006 was $486, $327, and $394, respectively. Future minimum rental payments for the rental of equipment on oil and gas properties are approximately $595, $275 and $7 for the years ended December 31, 2007, 2008 and 2009, respectively.

69

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

In August 2005, the Company entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma Farmers Union Sustainable Energy LLC to construct and operate an ethanol production plant in Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of ethanol, 176,000 tons of distillers dried grains and 2.8 Bcfe of CO₂ per year. The Company will have the option to acquire all or part of this CO₂ for use in its tertiary oil recovery projects. The start up and construction costs are estimated to be between $115 million and $125 million, with the Company having a 66.67% ownership interest. The Company expects Oklahoma Ethanol L.L.C. will receive between $69 million to $75 million in secured indebtedness with recourse limited to the Company’s interests in this entity to fund construction costs and for related start-up working capital. The Company expects to commence construction in late 2007 with completion in 2009, and that its equity contribution will be approximately $30 million to $33 million.

We entered into an agreement build a natural gas pipeline, a CO₂ pipeline, and compression facilities at an ethanol plant expected to be constructed and operational in 2007. The construction of these pipelines and facilities and the related costs are contingent on certain events and are currently estimated to be a minimum of $2,200. We also have a long-term contract to purchase all of the CO₂ manufactured at the ethanol plant, if built. Based on estimated plant capacity, it is estimated that we will purchase approximately 4.2 Mmcf per day at variable contract prices over the ten-year contract term with the possibility of renewal.

We have two additional long-term contracts that require us to purchase CO₂ for tertiary recovery projects. Under one contract we may purchase a variable amount of CO₂, up to 20.0 MMcf per day through July 1, 2010. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 15 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, which is consistent with our current level. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

The Company has an employment agreement with its chief financial officer which provides for an annual base salary, bonus compensation, phantom units and various benefits. The agreement provides for a minimum severance amount of $424 in the event of termination without cause, change of control, or termination, liquidation or dissolution of the Company. The severance agreement expires June 30, 2010.

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

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.

Note 14: Capital stock

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

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

Cash dividends of $3,409 and $1,049 were paid during the years ended December 31, 2005 and 2006, respectively. Dividends of $350 were paid on a quarterly basis from January 1, 2005 through September 30, 2006 and a one-time dividend of $2,000 was paid on February 1, 2005.

Note 15: 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:

	2004		2005		2006
Property acquisition costs
Proved properties(1)	$	28,483	$	216,742	$	484,404
Unproved properties		2,063		5,543		4,731
Total acquisition costs		30,546		222,285		489,135
Development costs		62,371		103,479		170,987
Exploration costs		3,114		7,274		7,015
Total	$	96,031	$	333,038	$	667,137

(1) Includes $152,945 of costs related to the acquisition of CEI Bristol in 2005 and $464,860 of costs related to the acquisition of Calumet in 2006.

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

        Oil and gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and exploratory wells in progress. Of the $18,299 of unproved property costs at December 31, 2006 being excluded from the amortization base, $1,415, $6,500 and $10,211 were incurred in 2004, 2005 and 2006, respectively, and $173 was incurred in prior years. These costs are primarily seismic and lease acquisition costs. The Company expects it will complete its evaluation of the properties representing the majority of these costs within the next two to five years.

Note 16: 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

70

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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.

The Company’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2004, 2005 and 2006 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2004	16,777		203,677		304,339
Purchase of minerals in place	3,724		39,894		62,238
Sales of minerals in place	(91	)	(201	)	(747	)
Extensions and discoveries	1,589		24,470		34,004
Revisions	2,051		2,229		14,535
Improved recoveries	5,708		5,474		39,722
Production	(1,173	)	(11,923	)	(18,961	)
Balance at December 31, 2004	28,585		263,620		435,130
Purchase of minerals in place	7,399		128,782		173,176
Sales of minerals in place	(45	)	(97	)	(367	)
Extensions and discoveries	569		19,117		22,531
Revisions	(1,975	)	4,334		(7,516	)
Improved recoveries	829		15,288		20,262
Production	(1,449	)	(16,660	)	(25,354	)
Balance at December 31, 2005	33,913		414,384		617,862
Purchase of minerals in place (as restated)	55,955		18,274		354,004
Sales of minerals in place	(78	)	(400	)	(868	)
Extensions and discoveries	762		12,164		16,736
Revisions(1)	(992	)	(50,471	)	(56,423	)
Improved recoveries	724		2,309		6,653
Production	(1,906	)	(20,949	)	(32,385	)
Balance at December 31, 2006 (as restated)	88,378		375,311		905,579
Proved developed reserves:
December 31, 2004	17,358		186,544		290,692
December 31, 2005	23,762		283,173		425,745
December 31, 2006	57,824		281,958		628,902

(1) The downward revision in our gas reserves in 2006 was primarily due to a decrease in price from $10.08 in 2005 to $5.64 in 2006 and an overall increase in lifting costs.

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

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

• 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;

71

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

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

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

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 4, “Derivative Activities and Financial Instruments”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate and year-end prices and costs are required by SFAS No. 69.

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

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

	2004			2005			2006 (restated)
Future cash flows	$	2,757,761		$	5,537,226		$	7,239,850
Future production costs		(908,239	)		(1,599,503	)		(3,144,707	)
Future development and abandonment costs		(186,381	)		(340,423	)		(577,123	)
Future income tax provisions		(567,468	)		(1,212,513	)		(953,794	)
Net future cash flows		1,095,673			2,384,787			2,564,226
Less effect of 10% discount factor		(581,632	)		(1,316,899	)		(1,482,017	)
Standardized measure of discounted future net cash flows	$	514,041		$	1,067,888		$	1,082,209

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. If the effects of hedging transactions were included in the computation, then future cash flows would have decreased by $29,332, $44,935, and $6,729 in 2004, 2005 and 2006, respectively.

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

	2004			2005			2006 (restated)
Beginning of year	$	325,250		$	514,041		$	1,067,888
Sale of oil and gas produced, net of production costs		(78,472	)		(144,637	)		(158,361	)
Net changes in prices and production costs		89,687			477,828			(472,700	)
Extensions and discoveries		56,933			83,727			52,366
Improved recoveries		73,199			68,467			6,538
Changes in future development costs		(69,721	)		(140,394	)		27,917
Development costs incurred during the period that reduced future development costs		11,230			8,456			30,989
Revisions of previous quantity estimates		32,775			(25,195	)		(137,268	)
Purchases and sales of reserves in place, net		109,754			496,645			408,000
Accretion of discount		49,565			78,483			161,752
Net change in income taxes		(99,260	)		(276,722	)		140,413
Changes in production rates and other		13,101			(72,811	)		(45,325	)
End of year	$	514,041		$	1,067,888		$	1,082,209

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

	2004		2005		2006
Oil (per Bbl)	$	43.51	$	61.04	$	61.06
Gas (per Mcf)	$	6.35	$	10.08	$	5.64

72

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements — (continued)

(Dollars in thousands, unless otherwise noted)

Reserve Restatement

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

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

	2006 As Reported	2006 As Restated
Oil (MBbls)	98,876	88,378
Total (Mmcfe)	968,567	905,579

Note 17: Subsequent events (unaudited)

On January 18, 2007, the Company issued $325,000 of 8 ⁷/8% Senior Notes due 2017, discounted at 99.178% of the principal amount. The net proceeds of $315,829, after underwriting and issuance costs, were used to pay down debt under our revolving credit line and for working capital.

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

73

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Based on their evaluation as of the end of the fiscal year ended December 31, 2006, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal Control Over Financial Reporting

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Executive Officers and Directors

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

Name	Age	Position
Mark A. Fischer	57	Chairman, Chief Executive Officer and President
Charles A. Fischer, Jr.	58	Chief Administrative Officer, Executive Vice President and Director
Joseph O. Evans	52	Chief Financial Officer and Executive Vice President and Director
Robert W. Kelly II	49	Senior Vice President and General Counsel
Larry E. Gateley	57	Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	44	Senior Vice President—Operations and Production Engineering

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

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

Joseph O. Evans, Chief Financial Officer & Executive Vice President & Director, joined Chaparral in July of 2005 as Chief Financial Officer and was elected to its Board of Directors in September 2006. From 1998 to June 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous Commission filings for clients. Mr. Evans has instructed numerous continuing professional education courses focused on compliance with the Sarbanes Oxley Act. He is a Certified Public Accountant and an Accredited Petroleum Accountant. Mr. Evans is a graduate of the University of Central Oklahoma with a Bachelor of Science degree in Accounting.

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

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

James M. Miller, Sr. Vice President—Operations & Production Engineering, joined Chaparral in 1996, as Operations Engineer. Since joining Chaparral, Mr. Miller has been promoted to positions of increasing responsibility and currently oversees all company production operations and field services. Mr. Miller has gained particular expertise in the area of operating secondary and tertiary recovery units. Prior to joining Chaparral, Mr. Miller worked for KEPCO Operating Inc. for one year as a petroleum engineer. From 1987 to 1995, he was employed by Robert A. Mason Production Co., as a petroleum engineer, and later as Vice President of Production. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Miller attended the University of Oklahoma and received a Bachelor of Science degree in Petroleum Engineering in 1986.

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ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION DISCUSSION AND ANALYSIS

Overview & Oversight of Compensation Program

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

Overview of Compensation Philosophy and Program

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

• drive and reward performance which supports the Company’s core values;

• align the interests of Senior Executives with those of stockholders;

• design competitive total compensation and rewards programs to enhance our ability to attract and retain knowledgeable and experienced Senior Executives; and

• set compensation and incentive levels that reflect mid-range market practices.

Benchmark Group and Compensation Targets

We selected a group of companies consisting of approximately 30 publicly-traded, U.S. exploration and production companies of varying sizes (the “Benchmark Group”). The Benchmark Group is used to index executive compensation levels against companies that have executive positions with responsibilities similar in breadth and scope to ours and that compete with us for executive talent.

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

Compensation Elements and Rationale for Pay Mix Decisions

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

(i) Compensation levels should be competitive

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

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(ii) Compensation should be related to performance

We believe that a significant portion of a Senior Executive’s compensation should be tied to individual performance and to overall Company performance measured primarily by growth in reserves, production and net income.

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

The Company intends for a portion of compensation paid to Senior Executives to be variable in order to allow flexibility when Company performance and/or industry conditions are not optimum and maintain the ability to reward Senior Executives for overall Company growth and retain Senior Executives when industry conditions necessitate. Senior Executives should have the incentive of increasing Company profitability and value in order to earn a portion of their compensation package.

(iv) Compensation should balance short and long-term performance

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

Review of Senior Executive Performance

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

Components of the Executive Compensation Program

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

• base salaries;

• annual bonus plans;

• long-term retention and incentive compensation; and

• health and welfare benefits and retirement.

Base Salaries

Senior Executive base salaries are targeted at median levels of similarly sized companies within the Benchmark Group and Survey Data. Base salaries are determined by evaluating a Senior Executive’s level of responsibility and experience and the Company’s performance.

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

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In setting the base salary of the Senior Executives for fiscal year 2006, the compensation of comparable senior executives based on Survey Data was reviewed. The PEO does not rely solely on predetermined formulas or a limited set of criteria when evaluating the performance of the Senior Executives.

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

• the current compensation demonstrates a significant deviation from the market data;

• recognizing outstanding individual performance;

• recognizing an increase in responsibility; or

• recognizing significant growth of the Company.

This is in line with our philosophy that Senior Executive compensation should be paid at the competitive median levels. The salaries paid to the PEO and the NEOs during fiscal year 2006 are shown in the Summary Compensation Table on page 83.

Annual Profit Sharing Bonus and Performance Based Retention Bonus

The Annual Profit Sharing Bonus provides Senior Executives with the opportunity to earn cash bonuses based on the Company’s achievement of unspecified Company-wide goals as determined by the PEO. The annual profit sharing bonus component of our compensation program is to align Senior Executive pay with our annual (short-term) performance. The profit sharing bonus was awarded to all employees. In 2006, one-half of the 2005 annual profit sharing bonus was paid in cash in June 2006 and for Senior Executives, the entire 2006 annual profit sharing bonus was paid in cash in December 2006.

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

Both the Profit Sharing and Retention Bonus for Senior Executives were discontinued after September 2006 and a new Officers Annual Bonus was created in September 2006. The Officers Annual Bonus provides Senior Executives with the opportunity to earn cash bonuses based on the Company’s achievement of unspecified Company-wide goals as determined by the CEO. The bonus is a component of the compensation program designed to align Senior Executive pay with our annual (short-term) performance. The bonus was awarded in September 2006 and is to be paid April 2, 2007.

The 2006 bonus programs were structured to provide cash bonuses to Senior Executives competitive to the median levels based on the Benchmark Group and the Survey Data to be consistent with our philosophy that compensation levels should be variable and competitive. The bonuses awarded paid to the PEO and the NEOs during fiscal year 2006 are shown in the Summary Compensation Table on page 83.

Phantom Unit Plan

The objective of the Phantom Unit plan is to provide non-owner Senior Executives and other key employees with long-term incentive and retention award opportunities in a private company that would be competitive with equity incentive plans provided by public companies. Phantom units may be awarded 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.

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Also, phantom units vest if a change of control event occurs. A change of control event will occur under the Plan if (1) our stockholders as of January 1, 2004, the date of the creation of the Phantom Unit Plan, collectively sell a majority of their shares (either publicly or privately) to a person who is not majority owned by them collectively, and in the process lose operational control of us (i.e., the position of President, Chief Executive Officer or Chairman of us or our subsidiary Chaparral Energy, is not held by either Mark A. Fischer or Charles A. Fischer, Jr.), (2) the termination, liquidation or dissolution of us or Chaparral Energy unless our business is substantially carried on by a successor company that remains majority owned or operationally controlled as described above, or (3) we sell all or substantially all of our assets. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately.

The Phantom Unit plan was effective January 1, 2004. At the creation of the plan, the value of the initial and nine subsequent annual awards made to Senior Executives was targeted. The value and timing of the awards was derived to provide an estimated pre-determined payout upon vesting of the awards. The payout on vesting of the awards assumed certain Company growth rates were sustained over the vesting period, although no adjustment is made to those awards if the Company exceeds or does not meet those growth rates. We believe that this aligns the Senior Executives compensation to stockholder value by providing a proprietary interest in the value of the Company. Additionally, the predetermined annual awards can be adjusted to recognize exemplary performance or increased responsibility consistent with the philosophy of relating individual compensation to performance.

Phantom unit information related to the NEOs during fiscal year 2006 is included in the Summary Compensation Table on page 83. Additional information on the phantom unit awards is shown in the Grants of Plan Based Awards Table on page 84 and the Outstanding Awards at Fiscal Year-End Table on page 84.

Tax Implications of Executive Compensation

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

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

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

Health and Welfare and Retirement Benefits

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

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

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

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

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

Participation Interests

Historically, we had granted participation interests in certain drilling or development projects to a limited number of employees with the objective of directly aligning Company and individual objectives. We granted certain participation interests in the form of overriding royalty interests to James M. Miller as incentive compensation for the development of our largest EOR project. The participation interests were granted subject to a vesting schedule to provide retention incentive through the initial phases of the long-term project. Our subsidiary, Chaparral CO₂, L.L.C., has assigned Mr. Miller an overriding royalty interest equal to a total 0.005 net revenue interest in the production from the Northwest Camrick Unit, the Camrick Unit and the North Perryton (George Morrow) Unit, in each case limited to the unitized Upper Morrow Sand formation. Mr. Miller was 60% vested at June 30, 2005, 80% vested at June 30, 2006 and is scheduled to be 100% vested at June 30, 2007, assuming he does not terminate his employment prior to that date. 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 or if we terminate Mr. Miller’s employment for any reason or if Chaparral Energy, Inc. merges into another entity in which Chaparral is not the surviving entity or if there is a sale of Chaparral Energy, Inc. 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. The participation interests information related to Mr. Miller during fiscal year 2006 is included in the Summary Compensation Table on page 83.

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We discontinued the program of granting overriding royalty interests to Senior Executives and other employees effective December 31, 2005, other than certain specified wells that spud prior to April 1, 2006.

Employment Agreements

We have an employment agreement with our chief financial officer, dated as of June 17, 2005. We agreed to pay Joseph O. Evans an annual salary of $212,000 and an aggregate bonus of not less than $50,000 for his first year of employment with us, which began July 1, 2005. In addition, on July 1, 2005, we granted Mr. Evans a $50,000 award under our Phantom Unit Plan. We have also agreed to pay Mr. Evans a minimum severance amount of $424,000 in bonus and phantom units if we terminate his employment without cause, if a change of control occurs, if Chaparral is terminated, liquidated or dissolved or if we sell substantially all of the assets of Chaparral, at any time before June 30, 2010. Our severance arrangement with Mr. Evans will terminate automatically after the completion of an initial public offering on the adoption of a revised severance package.

Indemnification Agreements

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

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

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

• us, except for:

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

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

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

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

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

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Board of Directors Report

The Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review and discussions, the Board of Directors recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

This report of the Board of Directors, acting as the Compensation Committee, shall not be deemed “soliciting material,” or to be “filed” with the Securities and Exchange Commission or subject to Regulation 14A or 14C or to the liabilities of Section 18 of the Securities Exchange Act of 1934 (the “Exchange Act”), except to the extent that the Company specifically requests that the information be treated as soliciting material or specifically incorporates it by reference into a document filed under the Securities Act of 1933 (the “Securities Act”) or the Exchange Act.

Mark A. Fischer

Charles A. Fischer, Jr.

Joseph O. Evans

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2006 SUMMARY COMPENSATION TABLE

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

Name and Principal Position	Year	Salary ($)		Bonus(1) ($)	Stock Awards(2) ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)			Total ($)
Mark A. Fischer, Chief Executive Officer and President	2006	$	351,258	245,165	—	—	—	—	$	20,688	(3)	$	617,111
Joseph O. Evans, Chief Financial Officer and Executive Vice President	2006		227,285	90,369	7,514	—	—	—		13,104	(3)		338,272
Charles A. Fischer, Chief Administrative Officer and Executive Vice President	2006		207,650	89,290	—	—	—	—		19,719	(3)		316,659
Larry E. Gateley, Senior Vice President - Reservoir Engineering and Acquisitions	2006		189,362	72,727	15,010	—	—	—		11,530	(3)		288,629
James M. Miller, Senior Vice President— Operations and Production Engineering	2006		170,885	67,463	15,010	—	—	—		99,514	(4)		352,872

⁽¹⁾ Includes amounts paid under the Annual Profit Sharing Bonus and Annual Performance Based Retention Bonus and amounts earned under the 2006 Officers Annual Bonus that is scheduled to be paid on April 2, 2007. The amounts of unpaid Officers Annual Bonuses at December 31, 2006 were $105,233, $45,817, $39,388, $32,851 and $31,996 for Messrs. Mark A. Fischer, Joseph O. Evans, Charles A. Fischer, Jr., Larry E. Gateley, and James M. Miller, respectively.

⁽²⁾ Phantom unit awards were made on January 1, 2006 and valued at $17.89 per share. The value shown is what is also included in the Company’s financial statements per FAS 123(R). The actual number of awards granted is shown in the “Grants of Plan Based Awards” table included in this filing.

⁽³⁾ Includes: for Mark A. Fischer $10,142 in matching 401(k) contributions; for Joseph O. Evans $12,667 in matching 401(k) contributions; for Charles A. Fischer $13,631 in matching 401(k) contributions; for Larry E. Gateley $10,822 in matching 401(k) contributions

⁽⁴⁾ Includes $10,318 in matching 401(k) contributions and $89,041 in payments pursuant to overriding royalty interests subject to vesting. We granted certain participation interests in the form of overriding royalty interests. Our subsidiary, Chaparral CO₂, L.L.C., has assigned Mr. Miller an overriding royalty interest equal to a total 0.005 net revenue interest in the production from the Northwest Camrick Unit, the Camrick Unit and the North Perryton (George Morrow) Unit, in each case limited to the unitized Upper Morrow Sand formation. Mr. Miller was 60% vested at June 30, 2005, 80% vested at June 30, 2006 and is scheduled to be 100% vested at June 30, 2007, assuming he does not terminate his employment prior to that date.

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2006 GRANTS OF PLAN-BASED AWARDS TABLE

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

Name	Grant Date	Estimated Future Payouts Under Non-Equity Incentive Plan Awards			Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Stock Awards: Number of Shares of Stock or Units(1) (#)	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/ Sh)
		Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)
Joseph O. Evans	1/1/2006							420		$	17.89
Larry E. Gateley	1/1/2006							839			17.89
James M. Miller	1/1/2006							839			17.89

⁽¹⁾ Phantom unit awards vest 7 years from the award date in accordance with the Phantom Unit Plan.

2006 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

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

	Option Awards					Stock Awards
	Number of Securities Underlying Unexercised Options (#)	Number of Securities Underlying Unexercised Options (#)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested(1) (#)	Market Value of Shares or Units of Stock That Have Not Vested(2) ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Name	Exercisable	Unexercisable
Joseph O. Evans						3,974	$	56,788
Larry E. Gateley						21,894		312,865
James M. Miller						21,894		312,865

⁽¹⁾ For Joseph O. Evans, phantom units vest as follows: 3,554 units on July 1, 2012 and 420 units on January 1, 2013; for Larry E. Gateley and James M. Miller, phantom units vest as follows: 19,306 units on January 1, 2011; 1,749 units on January 1, 2012; and 839 units on January 1, 2013.

⁽²⁾ The table assumes a market value of $14.29 at December 31, 2006 which is calculated in accordance with the provisions of the Phantom Unit Plan.

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POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

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

Employment Agreement with Joseph O. Evans

We have an employment agreement with Mr. Evans, dated as of June 17, 2005. We agreed to pay a minimum severance amount of $424,000 in bonus and phantom units if we terminate his employment without cause, if a change of control occurs, if Chaparral is terminated, liquidated or dissolved or if we sell substantially all of the assets of Chaparral, at any time before June 30, 2010. Our severance arrangement with Mr. Evans will terminate automatically after the completion of an initial public offering on the adoption of a revised severance package.

Phantom Unit Plan Awards

We have granted phantom unit awards to certain NEO’s and other key employees.

Full Vesting Upon a Change in Control

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

Under the Phantom Unit Plan, a Change in Control is deemed to occur if:

• the individuals who are stockholders at January 1, 2004, the date of creation of the Phantom Unit Plan, collectively sell a majority of their Membership Units (either publicly or privately) to a party which is not majority owned by them collectively, an in the process lose operation control (i.e., the position of President, Chief Executive Officer, or Chairman of the Board is not held by either Mark A. Fischer or Mr. Charles A. Fischer, Jr.); or

• Terminate the business of, or liquidate or dissolve the Company unless the business of the Company is substantially carried on by a successor company with is majority owned or operationally controlled by the stockholders at January 1, 2004, the date of creation of the Phantom Unit Plan; or

• Sell substantially all of the assets of the Company.

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

Pro Rata Vesting Upon Death, Disability, Retirement or Termination of Employment by Us Without Cause

Phantom units vest on a pro-rata basis on the January 1 or July 1 which immediately follows the Participants termination of employment with the company due to death, disability, retirement or termination of employment without cause. Pro-rata calculation will be accomplished by dividing the number of years elapsed for the award date to the date of vesting (to a maximum of 7 years) by seven and then multiplying the number of Phantom Units in the award by the result. Phantom units which do not vest hereunder will be forfeited to the company and the participant shall have no further rights with regard to the units. A participant is considered disabled if, in the sole determination of the Committee, such participant is subject to a physical or mental condition which renders or is excepted to render the participant unable to perform his or her usual duties for the Company. A Participant is considered retired if the participants’ full-time employment with the Company terminates at or after the date the Participant attains the age of 65 years. For each NEO, the number of shares with respect to which the forfeiture restrictions would have lapsed and the value of this accelerated vesting is specified above in the 2006 Outstanding Equity Awards Table.

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Participation Interests

We granted certain participation interests in the form of overriding royalty interests to James M. Miller as incentive compensation. Mr. Miller was 60% vested at June 30, 2005, 80% vested at June 30, 2006 and is scheduled to be 100% vested at June 30, 2007, assuming he does not terminate his employment prior to that date. 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 or if we terminate Mr. Miller’s employment for any reason or if Chaparral Energy, Inc. merges into another entity in which Chaparral is not the surviving entity or if there is a sale of Chaparral Energy, Inc. 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.

Other Payments Made Upon Termination, Retirement, Death or Disability

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

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

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Principal Stockholders

The following table sets forth information, as of March 16, 2007, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, and each of the five most highly compensated executive officers, by all directors and executive officers as a group.

Name(1)	Beneficial ownership
	Number	Percent
Mark A. Fischer(2)	372,500	42.5	%
Altoma Energy G.P.(3)	224,500	25.6	%
Charles A. Fischer, Jr.(4)	224,500	25.6	%
Chesapeake Energy Corporation(5)	280,000	31.9	%
Joseph O. Evans	—	—
Larry E. Gateley	—	—
James M. Miller	—	—
Robert W. Kelly II	—	—
All Directors and Officers as a group (6 persons)	597,000	68.1	%

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

(2) Fischer Investments, L.L.C. is the record owner of these shares of our common stock and is owned 50% by Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 50% 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 Altoma’s 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 224,500 shares owned of record by Altoma Energy G.P. Charles A. Fischer, Jr. serves as one of four managing partners of Altoma Energy G.P. Charles A. Fischer, Jr. owns directly a 22.25% general partner interest and his spouse owns directly a 0.90% general partner interest in Altoma Energy G.P.

(5) The address of Chesapeake Energy Corporation is 6100 North Western Avenue, Oklahoma City, Oklahoma 73118.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons, Promoters and Certain Control Persons

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

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

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

        On December 28, 2005, the Company’s chief executive officer acquired the Company’s beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112,000 in cash together with the assumption of a loan of $262,000, which represents the Company’s net book value and its estimated current fair market value. The house was acquired by the Company in April 2004 for the purchase price of $328,000. Record title was taken in the name of the Company’s chief executive officer, who entered into a mortgage securing the loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral used the house, the Company’s board of directors approved the payment by the Company of the downpayment on the house and the principal and interest payments on the loan. The Company made monthly payments of principal and interest totaling approximately $38,000 through November 2005.

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Stockholders’ Agreement

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

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

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

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

Listing of Shares; Right of First Offer. Under the Stockholders’ Agreement, Chaparral agrees to use its commercially reasonable efforts to effect a Qualified Initial Public Offering prior to August 15, 2011. Altoma agrees (i) not to transfer, without the consent of Fischer, any shares of Common Stock prior to such date except in connection with a Qualified Initial Public Offering, and (ii) in the event of a Qualified Initial Public Offering, to

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include in such offering a number of shares designated by Chaparral up to the number of shares being sold by Chaparral in such offering, but not to exceed $100 million without the consent of Altoma. If Chaparral’s shares of Common Stock are not listed on an exchange after August 15, 2011, Altoma may request to transfer up to 60% of its shares pursuant to a demand request as described below, but only after Altoma first offers such shares to Chaparral, and then to Chesapeake and Fischer, in accordance with the procedures set forth in the Stockholders’ Agreement.

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

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

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

Review, Approval or Ratification of Transactions with Related Persons

Our Board of Directors is responsible for approving all related party transactions between the Company and any officer or director that would potentially require disclosure. As of the date of this Form 10-K, the Board expects that any transactions in which related persons have a direct or indirect interest will be presented to the Board for review and approval. The Board has not adopted a written policy regarding related party transactions, but it makes inquiries to management and our auditors regarding any such transactions. The Company is not aware of any transaction that was required to be reported in its filings with the SEC where such policies and procedures either did not require review or were not followed.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Independent Auditor and Fees

Grant Thornton LLP, our independent registered public accounting firm, audited the Company’s consolidated financial statements for fiscal 2006. Grant Thornton LLP has billed the Company and its subsidiaries fees as set forth in the table below for (i) the audits of the Company’s 2005 and 2006 annual financial statements, reviews of quarterly financial statements, and review of the Company’s filings on Forms S-1 and S-4 and other documents filed with the Securities and Exchange Commission, (ii) assurance and other services reasonably related to the audit or review of the Company’s financial statements, and (iii) services related to tax compliance.

	Audit Fees		Audit-Related Fees		Tax Fees (1)
Fiscal 2006 (2)	$	477,688	$	255,111	$	39,156
Fiscal 2005 (2)	$	378,324	$	107,518	$	39,795

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(1) The services comprising “Tax Fees” included tax compliance, planning and advice.

(2) There were no fees billed in 2005 or 2006 that would constitute “All Other Fees.”

Pre-Approved Policies and Procedures

We currently have no Board committees. Our Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by Grant Thornton LLP during fiscal 2006 were approved by the Board of Directors.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Financial Statements, Schedules and Exhibits (1) Financial Statements — Chaparral Energy, Inc. and Subsidiaries:

The Financial Statements listed in the Index to Consolidated Financial Statements are filed as part of this report on Form 10-K (see Part II, Item 8-Financial Statements and Supplementary Data).

(2) Financial Statement Schedules

All other consolidated financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included elsewhere within this Form 10-K.

(3) Exhibits

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Exhibit No.	Description
3 .1*	Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.1 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
3 .2*	Amended and Restated Certificate of Incorporation of the Company, dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
3 .3*	Bylaws of the Company, dated as of September 14, 2005. (Incorporated by reference to Exhibit 3.2 of the Company’s Registration Statement on Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
3 .4*	Amended and Restated Bylaws of the Company, dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
3 .5*	Agreement and Plan of Merger, dated as of September 15, 2005, by and between the Company and Chaparral, L.L.C. (Incorporated by reference to Exhibit 3.2 to Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4 .1*	Form of 8  1/2% Senior Note due 2015 (included in Exhibit 4.2). (Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.2*	Indenture, dated as of December 1, 2005, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.3*	First Supplemental Indenture, dated as of August 24, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on August 28, 2006)
4.4*	Second Supplemental Indenture, dated as of October 31, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
4.5*	Indenture dated January 18, 2007, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
4.6*	Form of 8 7/8% Senior Note due 2017 (included in Exhibit 4.5). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
10.1*	Form of Mortgage (Incorporated by reference to Exhibit 10.4 to Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
10.2*	Limited Partner Interest Purchase and Sale Agreement, dated September 29, 2005, by and between TIFD III-X LLC and CEI Acquisition, L.L.C. (Incorporated by reference to Exhibit 10.5 to Form S-1, (SEC File No. 333-130749), filed on December 29, 2005)
10.3*	Form of Indemnification Agreements, between the Company and each of the directors and certain executive officers thereof (Incorporated by reference to Exhibit 10.6 to Form S-4 (SEC File No. 333-134748), filed on June 6, 2006)
10.4*	Form of Assignment of Overriding Royalty Interest to James M. Miller (Incorporated by reference to Exhibit 10.7 to Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
10.5*†	Phantom Unit Plan (Incorporated by reference to Exhibit 10.8 to Form S-1 (SEC File No. 333-130749), filed on February 14, 2006)

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Exhibit No.	Description
10.6*†	Letter Agreement dated June 14, 2005 re: Conditional Employment Offer with Joseph O. Evans (Incorporated by reference to Exhibit 10.9 to Form S-1 (SEC File No. 333-130749), filed on February 14, 2006)
10.7*	Common Stock Purchase Agreement, dated as of September 1, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
10.8*	Stockholders’ Agreement, dated as of September 29, 2006, by and among the Company, Chesapeake Energy Corporation, Altoma Energy and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
10.9*	Seventh Restated Credit Agreement, dated as of October 31, 2006, 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. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
10.10*	Securities Purchase Agreement, dated as of September 16, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
10.11*	First Amendment to Securities Purchase Agreement, dated as of October 31, 2006, by and among the Company, Calumet Oil Company, JMG Oil & Gas, L.P., J.M. Graves L.L.C. and each of the Sellers party thereto. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
10.12*	Registration Rights Agreement dated January 18, 2007, among the Company, the guarantors party thereto and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
21.1**	Subsidiaries of the Company
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Incorporated by reference

** Previously filed

† Management contract or compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CHAPARRAL ENERGY, INC.
By:	/s/ Mark A. Fischer
Name:	Mark A. Fischer
Title:	President and Chief Executive Officer

Date: January 3, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Date
/s/ Mark A. Fischer Mark A. Fischer	President, Chief Executive Officer and Chairman (Principal Executive Officer)	January 3, 2008
/s/ Joseph O. Evans Joseph O. Evans	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	January 3, 2008
/s/ Charles A. Fischer, Jr. Charles A. Fischer, Jr.	Director	January 3, 2008

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EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER PURSUANT TO

RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Mark A. Fischer, certify that:

1. I have reviewed this annual report on Form 10-K/A of Chaparral Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 3, 2008

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Joseph O. Evans, certify that:

1. I have reviewed this annual report on Form 10-K/A of Chaparral Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 3, 2008

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chaparral Energy, Inc. (the “Company”) on Form 10-K/A for the period ending December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mark A. Fischer, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Mark A. Fischer

Mark A. Fischer

Chief Executive Officer

Date: January 3, 2008

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Chaparral Energy, Inc. (the “Company”) on Form 10-K/A for the period ending December 31, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Joseph O. Evans, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

/s/ Joseph O. Evans

Joseph O. Evans

Chief Financial Officer

Date: January 3, 2008