UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2007

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 Smaller Reporting Company  ¨

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 March 24, 2008.

CHAPARRAL ENERGY, INC.

Index to Form 10-K

Part I
Items 1. and 2. Business and Properties	5
Item 1A. Risk Factors	23
Item 1B. Unresolved Staff Comments	31
Item 2. Properties	31
Item 3. Legal Proceedings	31
Item 4. Submission of Matters to a Vote of Security Holders	32
Part II
Item 5. Market Price for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Item 6. Selected Financial Data	34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	53
Item 8. Financial Statements and Supplementary Data	55
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A. Controls and Procedures	86
Item 9B. Other Information	87
Part III
Item 10. Directors, Executive Officers and Corporate Governance	88
Item 11. Executive Compensation	90
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	101
Item 13. Certain Relationships and Related Transactions, and Director Independence	102
Item 14. Principal Accountant Fees and Services	105
Part IV
Item 15. Exhibits and Financial Statement Schedules	106
Signatures	109

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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.

Enhanced oil recovery (EOR) The use of any improved recovery method, including injection of CO₂, or polymer, to remove additional oil after secondary recovery.

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.

NYMEX The New York Mercantile Exchange.

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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.

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 layers of 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. We have provided definitions of terms commonly used in the oil and gas industry in the “Glossary of terms” beginning on page 2.

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 Gulf Coast, Ark-La-Tex, North Texas, 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 were complementary to our existing core areas of operations and had estimated proved reserves of 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 EOR opportunities.

As of December 31, 2007, we had estimated proved reserves of 987 Bcfe (65% proved developed and 60% crude oil) with a PV-10 value of approximately $2.7 billion. For the year ended December 31, 2007, our average daily production was 111.3 MMcfe. As of December 31, 2007, our estimated reserve life was 24.3 years. For the year ended December 31, 2007, our oil and gas revenues were $366.0 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 pages 16 and 17.

For the period from 2004 to 2007, our proved reserves and production grew at a compounded annual growth rate of 31% and 29%, 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 developmental drilling, acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

For the year ended December 31, 2007, we made capital expenditures of $230.2 million, including $106.1 million for development drilling and $49.8 million for acquisitions, of which $15.6 million was a release from escrow and other purchase price allocation adjustments of the prior year’s 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 2004 to 2007, we have grown reserves and production by a compounded annual growth rate of 31% and 29%, respectively. We have achieved this through a combination of drilling and acquisition success. 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

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averaged 664% per year since 2001. We replaced approximately 822%, 991% and 301%, as further discussed beginning on page 15, of our production in 2005, 2006 and 2007 respectively, at an average fully developed FD&A cost of $3.00 per Mcfe over this three-year period.

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 2005, 2006 and 2007, our capital expenditures for acquisitions of proved properties were $216.7 million, $484.4 million and $41.7 million, respectively. These acquisition capital expenditures represented approximately 65%, 73% and 18%, respectively, of our total capital expenditures and approximately 80%, 94% and 13%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. 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, 2007, we had an inventory of over 1,475 proved developmental drilling locations and 4,780 additional potential drilling locations, shown in the following table which combined represent over 18 years of drilling opportunities based on our 2008 drilling rate.

	Identified proved undeveloped drilling locations	Identified additional potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net
Mid-Continent	905	3,645	379,072	60,059
Permian Basin	92	732	51,291	21,461
Gulf Coast	11	69	44,718	11,887
Ark-La-Tex	12	45	15,277	—
North Texas	352	193	19,445	5,676
Rocky Mountains	103	96	15,201	9,794
Total	1,475	4,780	525,004	108,877

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 23. We have experienced a high historical drilling success rate of approximately 98% on a weighted average basis during 2005, 2006 and 2007. For the year ended December 31, 2007, we spent $106.1 million to drill 56 (52 net) operated wells and to participate in 167 (7 net) wells operated by others, representing 36% of our increases in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries. For 2008, we have budgeted $118.0 million to drill more than 130 operated wells and to participate in more than 200 wells operated by others. To support our drilling program, we have entered into agreements which allow access to approximately 43,000 square miles of non-proprietary 3-D seismic data, conducted four proprietary 3-D seismic shoots and received permits for one additional proprietary 3-D survey.

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Enhanced oil recovery expertise and assets. Beginning in 2000, we expanded our operations to include CO₂ EOR. CO₂ EOR 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 EOR operations, and we also have specific software for modeling CO₂ EOR. We own a 29% interest in and operate a large CO₂ EOR unit in southern Oklahoma and installed and operate a second CO₂ EOR unit with a 54% interest in the Oklahoma panhandle. At December 31, 2007, our proved reserves included four properties where CO₂ EOR recovery methods are used, which comprise approximately 6% of our total proved reserves. In addition, we operate a polymer EOR flood in the North Burbank unit. This unit is in the early phases of an polymer EOR 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 polymer EOR program and ultimately introduce CO₂ injection into this unit.

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 36 years after starting his career at Exxon as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 28 years of experience in the oil and gas industry. Individuals in our 23-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, EOR 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, 2007, we spent approximately $106.1 million on development drilling, which represents 46% 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. We currently plan to spend $118.0 million, or approximately 56% of our capital expenditures, on developmental drilling in 2008.

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 2005 and 2006 we have also made larger acquisitions that complemented our existing properties in our core areas. During the year ended December 31, 2007, we made acquisitions of approximately $49.8 million, or 22% of our total capital expenditures for such period. Our 2008 acquisition capital budget for oil and gas properties is $35.0 million, or 17% of our total capital expenditure budget.

Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 17 field offices throughout Oklahoma, Texas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor. As of December 31, 2007, we had an inventory of 818 developed enhancement projects requiring total estimated capital expenditures of $43.8 million.

Expand CO₂ EOR activities. We have accumulated interests in 54 properties in Oklahoma and Texas that meet our criteria for CO₂ EOR operations and are expanding our CO₂ pipeline system to initiate CO₂ injection in

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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 late 2008. To support our existing CO₂ EOR projects, we currently inject approximately 38.5 MMcf per day of purchased and recycled 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 a 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and southwestern Kansas that will enhance our CO₂ plans in this area.

Pursue modest exploration program. In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $10.0 million, or approximately 5% of our 2008 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, 2007, we operated properties comprising approximately 84% of our proved reserves.

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our proved developed production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of December 31, 2007, we had swaps in place for approximately 73% and 23% of our most recent internally estimated proved developed gas production for 2008 and 2009, respectively. We also had swaps in place for approximately 77% of our most recent internally estimated proved developed oil production for 2008 through 2011. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in losses on oil and gas hedging activities of $68.3 million, $4.2 million and $28.1 million for the years ended December 31, 2005, 2006 and 2007, respectively, through a period of increasing commodity prices. The years ended December 31, 2006 and 2007 also include non-hedge derivative losses of $4.7 and $23.8 million, respectively.

Oklahoma Ethanol L.L.C.

In April 2007, Oklahoma Ethanol L.L.C. agreed to construct and operate an ethanol plant in Blackwell, Oklahoma. The ethanol plant is estimated to produce a minimum of 50 million gallons of denatured ethanol annually. 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 EOR 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 2008 with completion in 2010, and that our equity contribution will be approximately $30 million to $33 million.

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Properties

The following table presents proved reserves and PV-10 value as of December 31, 2007 and average daily production for the year ended December 31, 2007 by our areas of operation.

	Proved reserves as of December 31, 2007							Average daily production (MMcfe per day) Year ended December 31, 2007
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	Percent of total MMcfe		PV-10 value ($mm)
Mid-Continent	83,061	259,022	757,388	76.7	%	$	2,041.2	72.1
Permian Basin	8,069	59,894	108,308	11.0	%		306.8	17.2
Gulf Coast	2,201	38,324	51,530	5.2	%		139.6	10.4
Ark-La-Tex	1,170	21,670	28,690	2.9	%		62.5	5.2
North Texas	2,326	4,644	18,600	1.9	%		65.3	3.8
Rocky Mountains	2,277	8,715	22,377	2.3	%		56.6	2.6
Total	99,104	392,269	986,893	100.0	%	$	2,672.0	111.3

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, 80% of our 2007 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, 2007 we owned interests in 8,627 gross (3,049 net) producing wells and we operated wells representing 84% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

Mid-Continent

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2007, accounted for 77% of our proved reserves and 76% of our PV-10 value. We own an interest in 5,747 producing wells in the Mid-Continent, of which we operate 2,238. Our 11 largest properties in terms of PV-10 value, are located in this area. During the year ended December 31, 2007, our net average daily production in the Mid-Continent Area was approximately 72.1 MMcfe per day, or 65% of our total net average daily production. This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is our largest property. The unit was developed in the early 1920’s and is 23,080 acres in size and has a cumulative production of 316 MMBbl of oil (primary and secondary). The North Burbank Unit accounted for 204,622 MMcfe of our proved reserves, $438.7 million of our PV-10 value as of December 31, 2007 and 1,564 MMcfe of our year ended December 31, 2007 production. The producing zone is Red Fork and Bartlesville and occurs at a depth of 3,000 feet. We own 99.25% of the field and we are also the operator. As of December 31, 2007, the field was producing 1,450 Bbl per day from 240 producing wells. There are also 157 active injection wells and 544 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 project on 1,440 acres. Production increased from 500 Bbls per day to 1,200 Bbl per day in this project area as a result of the polymer injection program. The project was shut down in 1986 due to low oil prices. We have already reinstituted a polymer flood on 485 acres adjacent to Block A on a 19 well pattern. Since taking over the field on November 1, 2006, we have already returned 32 temporarily abandoned wells to production with initial rates of production ranging between 6-25 Bbls per day. We believe that this field also may have upside with the injection of CO₂.

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Camrick area—Beaver and Texas Counties, Oklahoma. The Camrick area represents approximately 5% of our proved reserves and 7% of our PV-10 value of our proved reserves (46,024 MMcfe and $198.6 million, respectively) at December 31, 2007. 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 16.6 MMBbl of primary reserves and approximately 13.1 MMBbl of secondary reserves. There are approximately 46 active producing wells in this area that produced 2,731 MMcfe during the year ended December 31, 2007. Currently CO₂ injection operations are continuing in the Phase I and II areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Area from approximately 115 Bbls (690 Mcfe) per day in 2001 from 11 wells to approximately 1,578 Bbls (9,468 Mcfe) per day at the year end December 31, 2007 from 46 producing wells. We plan to continue expansion of 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 or our proved reserves (34,968 MMcfe and $90.6 million, respectively) at December 31, 2007. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946 and produced 1,202 MMcfe during the year ended December 31, 2007. 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 28 active producing wells in this unit. We are scheduled to drill 14 wells in 2008.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Play accounted for 11,029 MMcfe of our proved reserves, $31.3 million of our PV-10 value of our proved reserves as of December 31, 2007 and 939 MMcfe of our year ended December 31, 2007 production. 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 25 Cleveland Sand producing wells, and we drilled three wells in each of 2005 and 2006. We drilled five wells in 2007 and have scheduled an additional 10 wells in 2008. We have employed horizontal drilling technology in most of our drilled wells in this area. We expect that future wells will utilize horizontal technology.

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. This unit accounted for 15,777 MMcfe of our proved reserves, $47.7 million of our PV-10 value as of December 31, 2007 and 709 MMcfe of our year ended December 31, 2007 production. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO₂ injection program was initiated in 1982. This miscible CO₂ injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996 miscible CO₂ injection began in the downdip section of the Sims C2. We currently have 47 active producing wells in this unit.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit which is 2,235 acres was discovered in 1915 and unitized in 1977. This unit had proved reserves of 30,116 MMcfe and a PV-10 value of $109.2 million at December 31, 2007. We operate this unit with a working interest of 80.2%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 14 MMBbls of oil and the unit currently has 63 producing wells and 46 active injection wells. The unit is currently producing 433 Bbls per day. We have completed 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. Production from all

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four wells has added about 86 Bbls of oil per day to the unit production along with about 30 Bbls of oil per day from the Sims reservoir still under a retrievable bridge plug. This Sims reservoir is prospective in much of the field. With the successful completion of this pilot program, we believe this could open up 86 additional drilling locations in the area and have five wells planned as part of our 2008 drilling program. None of the Sims reserves were booked as PUD reserves at year end 2007. 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. This unit represents 17,598 MMcfe of our proved reserves and $70.9 million of our PV-10 value at December 31, 2007. There are currently 27 producing wells and 15 active injection wells, with current production of approximately 267 Bbls 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. Two wells are scheduled to be drilled in 2008 in this unit.

CO₂ EOR—Various counties, Oklahoma and Texas. We have initiated CO₂ injection in our Perryton Unit in December 2006 and anticipate initiating CO₂ injection in our NW Camrick Unit in late 2008 and three Booker Inland units in 2008. We have in place transportation and supply agreements to provide the necessary CO₂ for these projects. Including properties recently purchased in the Calumet acquisition, we have accumulated 54 properties in Oklahoma and Texas that meet our criteria for CO₂ EOR 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, own a 58% interest in and operate the 23 mile Purdy to Velma CO₂ pipeline and we own 100% interest in approximately 126 miles of pipeline located in the panhandle of Oklahoma and southwestern Kansas. 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 EOR processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2007, accounted for 11% of our proved reserves and 11% of our PV-10 value. We own an interest in 1,497 wells in the Permian Basin, of which we operate 383. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2007, our net average daily production in the Permian Basin Area was approximately 17.2 MMcfe per day, or 15% of our total net average daily production. Similar to the Mid-Continent Area, it is characterized by its stable long-life, shallow decline reserves.

Tunstill Field Play—Loving and Reeves Counties, Texas. Our Tunstill Field Play covers approximately 19,840 acres. We operate these wells with a working interest of 100%. The Tunstill field play represents 18,197 MMcfe of our proved reserves, $55.3 million of our PV-10 value at December 31, 2007 and 1,322 MMCfe of our year ended December 31, 2007 production. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds while more recent wells have established production from the deeper Cherry Canyon Sands as well as the shallower sands. During 2006, we drilled ten wells in this play. We drilled eight wells in 2007 and have plans to drill 19 wells in 2008.

Haley Area Play—Loving County, Texas. The Haley Area: Bone Springs, Atoka, Strawn and Morrow Play encompasses 3,840 gross acres. We own interests in and operate 10 producing wells in this play. The Haley Area represents 16,737 MMcfe of our proved reserves, $41.7 million of our PV-10 value at December 31, 2007 and

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1,491 MMcfe of our year ended December 31, 2007 production. Production has been established from four main intervals: the Bone Springs at a depth of approximately 10,100–11,000 feet, the Atoka at a depth of approximately 16,000 feet, the Strawn at a depth of approximately 15,500 feet and the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Atoka, two are completed in the Strawn, three wells are completed in the Morrow and three are completed in the Bone Springs. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Atoka/Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. During 2007, we drilled two wells in this area. The Haley 38-3 is currently producing approximately 45 Bbl per day and 95 Mcf per day from the Bone Springs. The Haley 38-4 is currently producing approximately 46 Bbls per day and 49 Mcf per day from the Bone Springs. Additional developmental Bone Springs wells will follow. We are currently drilling the Bowdle Estate 47-2 to test the Morrow, which offsets an Anadarko well that is producing from the Morrow at 20 Mmcf per day. We also drilled the F.D. Russell #2 well which encountered several Atoka sands and is currently in the completion process.

Gulf Coast

The Gulf Coast is the most active of our four growth areas and, as of December 31, 2007, accounted for 5% of our proved reserves and 5% of our PV-10 value. We own an interest in 305 wells in the Gulf Coast area, of which we operate 209. 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 own interest in approximately 9,018 net producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate 10 active producing wells in this area. As of December 31, 2007, the wells in Nueces County, Texas account for 7,845 MMcfe of our proved reserves, $36.6 million of our PV-10 value and 219 MMcfe of our year ended December 31, 2007 production. We are currently processing a 60 sq. mile proprietary 3D seismic survey over parts of this area where we have entered into an area of mutual interest with a 50% ownership in an attempt to find bypassed reserves or other potential reservoirs.

Vivian Borchers Area—Lavaca County, Texas. We control approximately 1,300 acres in the Vivian Borchers Area. As of December 31, 2007, the wells in Lavaca County, Texas accounted for 1,762 MMcfe of our proved reserves, $4.8 million of our PV-10 value and 100 MMcfe of our year ended December 31, 2007 production. Multiple Frio and Miocene pay zones occur at depths shallower than 4,000 feet. Based on 3-D seismic reprocessing, we have successfully drilled and completed three wells to depths of approximately 4,000 feet. These wells had initial test rates as high as 900 Mcf of natural gas per day. In addition, we have several deep 3-D seismic based Wilcox tests planned for the area. We recently drilled the Vivian Borchers #2-14 to a depth of 13,000 ft., developed production from 12,116 to 12,582 ft. and as of January 2008 we are producing the well at 1,351 Mcf per day and 24 Bbls condensate per day. We have licensed 200 square miles of 3D seismic data and are currently evaluating it for additional prospects, similar to those mentioned above. As prospects are identified, we expect to propose and budget additional leasing and drilling activity.

Ark-La-Tex

As of December 31, 2007, the Ark-La-Tex area accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 135 wells in the Ark-La-Tex area, of which we operate 71. These reserves are characterized by shorter life and higher initial potential.

North Texas

As of December 31, 2007, the North Texas area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 758 wells in the North Texas area, of which we operate 138. One of our four proprietary 3-D seismic surveys has been completed in this area.

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Rocky Mountains

As of December 31, 2007, the Rocky Mountains area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 185 wells in the Rocky Mountains area, of which we operate 48. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

Oil and Natural Gas Reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2007. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value) and by Lee Keeling & Associates, Inc. (52% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% of PV-10 value).

	Net proved reserves
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	PV-10 value (In thousands)
Developed—producing	48,451	220,134	510,840	$  1,481,935
Developed—non-producing	13,117	49,445	128,147	350,836
Undeveloped	37,536	122,690	347,906	839,211
Total proved	99,104	392,269	986,893	$2,671,982

The estimated reserve life as of December 31, 2005, 2006 and 2007 was 24.4, 28.0 and 24.3 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)	2005		2006		2007
Future net revenue	$	3,597,300	$	3,518,020	$	6,203,720
PV-10 value		1,602,610		1,494,063		2,671,982
Standardized measure of discounted future net cash flows		1,067,888		1,082,209		1,793,980
Oil price (per Bbl)	$	61.04	$	61.06	$	96.01
Natural gas price (per Mcf)	$	10.08	$	5.64	$	6.80

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, 2007 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	5,813	2,252
Natural gas	2,814	797
Total	8,627	3,049

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The following table details our gross and net interest in producing wells in which we have an interest and the number of wells we operated at December 31, 2007 by area.

	Total wells		Operated Wells
	Gross	Net
Mid-Continent	5,747	2,191	2,238
Permian Basin	1,497	402	383
Gulf Coast	305	197	209
Ark-La-Tex	135	72	71
North Texas	758	141	138
Rocky Mountains	185	46	48
Total	8,627	3,049	3,087

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2007 by area.

	Developed		Undeveloped
	Gross	Net	Gross	Net
Mid-Continent	901,522	379,072	69,970	60,059
Permian Basin	88,616	51,291	22,521	21,461
Gulf Coast	76,084	44,718	19,911	11,887
Ark-La-Tex	27,817	15,277	—	—
North Texas	26,391	19,445	6,187	5,676
Rocky Mountains	44,238	15,201	20,349	9,794
Total	1,164,668	525,004	138,938	108,877

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.

	2005				2006				2007
	Gross		Net		Gross		Net		Gross		Net
Development wells
Productive	171.0		52.0		189.0		56.1		214.0		51.7
Dry	2.0		0.8		1.0		0.2		3.0		1.2
Exploratory wells
Productive	11.0		6.0		1.0		1.0		6.0		5.9
Dry	1.0		0.4		1.0		0.1		0.0		0.0
Total wells
Productive	182.0		58.0		190.0		57.1		220.0		57.6
Dry	3.0		1.2		2.0		0.3		3.0		1.2
Total	185.0		59.2		192.0		57.4		223.0		58.8
Percent productive	98	%	98	%	99	%	99	%	99	%	98	%

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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, 2005, 2006 and 2007), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2005, 2006 and 2007 were prepared by Cawley, Gillespie & Associates (36% of PV-10 value in 2007) and Lee Keeling & Associates, Inc. (52% of PV-10 value in 2007). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% of PV-10 value).

	As of December 31,
Proved Reserves	2005			2006			2007
Oil (Mbbl)		33,913			88,378			99,104
Natural gas (MMcf)		414,384			375,311			392,269
Natural gas equivalent (MMcfe)		617,862			905,579			986,893
Proved developed reserve percentage		69	%		69	%		65	%
PV-10 value (in thousands)	$	1,602,610		$	1,494,063		$	2,671,982
Estimated reserve life (in years)(1)		24.4			28.0			24.3
Cost incurred (in thousands):
Property acquisition costs
Proved properties(2)	$	216,742		$	484,404		$	41,724
Unproved properties		5,543			4,731			8,032
Total acquisition costs		222,285			489,135			49,756
Development costs		103,479			170,987			165,177
Exploration costs		7,274			7,015			15,287
Total	$	333,038		$	667,137		$	230,220
Annual reserve replacement ratio(3)		822	%		991	%		301	%
Three-year average fully developed FD&A cost ($/Mcfe)(4)	$	1.82		$	2.37		$	3.00

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

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

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

	Year ended December 31,
	2005				2006				2007
	Reserves replaced		Percent of total		Reserves replaced		Percent of total		Reserves replaced		Percent of total
Purchases	683	%	83.1	%	1,093	%	110.3	%	46	%	15.4	%
Extensions and discoveries	89	%	10.8	%	52	%	5.2	%	214	%	70.9	%
Revisions	(30	)%	(3.6	)%	(174	)%	(17.6	)%	(71	)%	(23.4	)%
Improved recoveries	80	%	9.7	%	20	%	2.1	%	112	%	37.1	%
Total	822	%	100.0	%	991	%	100.0	%	301	%	100.0	%

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(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):

	2005			2006			2007
Purchases of minerals in place		173,176			354,004			18,850
Extensions and discoveries		22,531			16,736			86,788
Revisions		(7,516	)		(56,423	)		(28,684	)
Improved recoveries		20,262			6,653			45,423
Total reserve additions		208,453			320,970			122,377
Costs incurred	$	333,038		$	667,137		$	230,220
Changes in future development costs		154,042			236,700			337,438
Total costs incurred	$	487,080		$	903,837		$	567,658
Three-year average fully developed FD&A cost ($/Mcfe)	$	1.82		$	2.37		$	3.00

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,
	2005		2006		2007
Production:
Oil (MBbl)		1,449		1,906		3,356
Natural Gas (MMcf)		16,660		20,949		20,504
Combined (MMcfe)		25,354		32,385		40,640
Average daily production:
Oil (Bbls)		3,970		5,222		9,195
Natural gas (Mcf)		45,644		57,395		56,175
Combined (Mcfe)		69,464		88,727		111,345
Average prices (before effect of hedges):
Oil (per Bbl)	$	53.76	$	61.65	$	69.85
Natural Gas (per Mcf)		7.41		6.29		6.41
Combined (per Mcfe)		7.94		7.69		9.00
Average costs per Mcfe:
Lease operating	$	1.66	$	2.21	$	2.57
Production tax	$	0.58	$	0.58	$	0.65
Depreciation, depletion, and amortization	$	1.24	$	1.61	$	2.11
General and administrative	$	0.39	$	0.45	$	0.54

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, 2007 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,

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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, 2007 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	$	2,041.2	$	631.5	$	1,409.7
Permian Basin		306.8		116.1		190.7
Gulf Coast		139.6		62.6		77.0
Ark-La-Tex		62.5		22.6		39.9
North Texas		65.3		26.1		39.2
Rocky Mountains		56.6		19.1		37.5
Total	$	2,672.0	$	878.0	$	1,794.0

Competition

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

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

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

Markets

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

• the amount of crude oil and natural gas imports;

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

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

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

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

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

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

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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, 2006 and 2007, 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. 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 2008 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

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persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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

Water Discharges

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

Air Emissions

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

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

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impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Other Regulation of the Oil and Gas Industry

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

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

Drilling and Production

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

• the location of wells;

• the method of drilling and casing wells;

• the rates of production or “allowables”;

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

• the plugging and abandoning of wells; and

• notice to surface owners and other third parties.

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

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Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

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

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

Natural Gas Gathering Regulations

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

State Regulation

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

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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, 2007, we had 726 full-time employees, including 12 geologists and geophysicists, 26 reservoir, production, and drilling engineers and 12 land professionals. Of these, 265 work in our Oklahoma City office and 461 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.

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;

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• 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.

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 EOR 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, 2007 future cash flows used realized prices based on a Henry Hub spot price of $6.80 per MMBtu for natural gas and a WTI Cushing spot price of $96.01 per Bbl for oil.

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A significant portion of total proved reserves as of December 31, 2007 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2007, approximately 35% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and EOR operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

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

As of December 31, 2007, 14% of our proved reserves were based on EOR methods including the injection of CO₂ and polymers, a synthetic chemical. Some of these properties have not been injected with CO₂ or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or in the production levels we anticipate. Our ability to develop future reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have material adverse affect on our financial condition, results of operations and reserves.

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

As of December 31, 2007, our total debt was $1,114.2 million. Our maximum commitment amount and the borrowing base under our Seventh Restated Credit Agreement was $525.0 million as of November 1, 2007. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

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

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

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

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

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

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

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

If an event of default occurs under our Credit Agreement or our 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.

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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 was $525.0 million as of November 1, 2007, and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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

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

• 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 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 35% of our total estimated proved reserves (by volume) at December 31, 2007 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will

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require significant capital expenditures and successful drilling and EOR operations. Our historical December 31, 2007 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 13.5%, 10.8% and 8.1% for the next three years. 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.

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

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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, 2007, we had entered into swaps for 17,840 MMcf of our natural gas production for 2008 through 2009 at average monthly prices ranging from $7.79 to $9.15 per Mcf of natural gas. As of December 31, 2007, we had entered into swaps for 8,509 MBbl of our crude oil production for 2008 through 2011 at average monthly prices ranging from $63.16 to $70.33 per Bbl of oil. As of December 31, 2007, we had basis protection swaps for 11,240 Mcf for 2008 through 2009 at average monthly prices ranging from $0.81 to $1.16 per mcf. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2007 was a liability of approximately $150.5 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

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

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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 2005, 2006, or 2007.

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.

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

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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 “Directors, Executive Officers and Corporate Governance.” 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;

• 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.

30

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, 2007 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 $525.0 million, equal to our borrowing base at December 31, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.25 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.

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 2. PROPERTIES

See Item 1. Business—Oil and Gas Operations. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See “Commitments and Obligations” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 14, “Commitments and Contingencies,” to the Consolidated Financial Statements for the future minimum rental payments. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

Pursuant to the securities purchase agreement dated as of September 16, 2006, as amended, relating to the acquisition of Calumet, we recorded a receivable of approximately $14.4 million due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, we received a communication from the sellers disputing the calculation of the purchase price adjustment. We believe the value

31

of the receivable was calculated in accordance with the securities purchase agreement and intend to diligently defend our position. On September 13, 2007, we filed a petition in the District Court of Tulsa County, State of Oklahoma, against John Milton Graves Trust u/t/a 6/11/2004, et al, seeking a declaratory judgment confirming this position. As of December 31, 2007, the recorded receivable was approximately $14.4 million and was recorded in other assets on the consolidated balance sheet.

In the opinion of management, there are no other 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.

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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 24, 2008, we had 877,000 shares of common stock outstanding held by three record holders.

Cash dividends of $1.0 million was paid during the year ended December 31, 2006. 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, 2007 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)	2003			2004			2005			2006			2007
Operating results data:
Revenues
Oil and gas sales	$	74,186		$	113,546		$	201,410		$	249,180		$	365,958
Loss on oil and gas hedging activities		(12,220	)		(21,350	)		(68,324	)		(4,166	)		(28,140	)
Service company sales		—			—			—			—			20,611
Total revenues		61,966			92,196			133,086			245,014			358,429
Costs and expenses
Lease operating		19,520			26,928			42,147			71,663			104,469
Production taxes		4,840			8,272			14,626			18,710			26,216
Depreciation, depletion and amortization		10,376			17,533			31,423			52,299			85,842
General and administrative		4,946			5,985			9,808			14,659			21,838
Service company expenses		—			—			—			—			18,441
Total costs and expenses		39,682			58,718			98,004			157,331			256,806
Operating income		22,284			33,478			35,082			87,683			101,623
Non-operating income (expense)
Interest expense		(4,116	)		(6,162	)		(15,588	)		(45,246	)		(87,656	)
Non-hedge derivative losses		—			—			—			(4,677	)		(23,781	)
Other income		208			279			665			792			2,276
Net non-operating expense		(3,908	)		(5,883	)		(14,923	)		(49,131	)		(109,161	)
Income (loss) from continuing operations before income taxes, minority interest and accounting change		18,376			27,595			20,159			38,552			(7,538	)
Income tax expense (benefit)		6,932			9,880			7,309			14,817			(2,745	)
Minority interest		—			—			—			(71	)		—
Income (loss) from continuing operations before accounting change		11,444			17,715			12,850			23,806			(4,793	)
Cumulative effect of change in accounting principle, net of income taxes		(887	)		—			—			—			—
Net income (loss)	$	10,557		$	17,715		$	12,850		$	23,806		$	(4,793	)
Income (loss) per share from continuing operations (basic and diluted)	$	14.77		$	22.86		$	16.58		$	29.74		$	(5.47	)
Income (loss) per share from accounting change, net		(1.15	)		—			—			—			—
Net income (loss) per share (basic and diluted)	$	13.62		$	22.86		$	16.58		$	29.74		$	(5.47	)
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			775,000			775,000			800,500			877,000
Cash flow data:
Net cash provided by operating activities	$	32,541		$	46,870		$	55,744		$	89,198		$	113,858
Net cash used in investing activities		(55,213	)		(92,141	)		(325,068	)		(703,848	)		(239,857	)
Net cash provided by financing activities		26,146			54,061			257,080			621,855			128,883

	As of December 31,
(Dollars in thousands)	2003			2004			2005			2006			2007
Financial position data:
Cash and cash equivalents	$	5,052		$	13,842		$	1,598		$	8,803		$	11,687
Total assets		211,086			308,827			647,379			1,331,435			1,530,898
Total debt		118,355			176,622			446,544			976,272			1,114,237
Retained earnings		30,977			48,692			58,126			80,883			76,090
Accumulated other comprehensive loss, net of income taxes		(4,900	)		(12,107	)		(47,967	)		(3,946	)		(73,839	)
Total equity		26,078			36,586			10,167			177,864			103,178
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 EOR projects. As of December 31, 2007, we had estimated proved reserves of 987 Bcfe, with a PV-10 value of $2.7 billion. Our reserves were 65% proved developed and 60% 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 13.5%, 10.8% and 8.1% for the next three years. 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;

35

• 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.

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:

• Private equity sale. On September 29, 2006, we sold 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 346 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 EOR 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.

• 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 are 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 $1.7 million toward the design for the construction of the plant for the year ended December 31, 2007.

• Green Country Supply Acquisition. On April 16, 2007, we acquired all of the outstanding shares of stock of Green Country Supply, Inc., or GCS, for $25.0 million. Approximately $5.0 million of the purchase price was deposited into escrow as security for certain potential working capital, environmental and employment adjustments. GCS was owned by the former shareholders of Calumet Oil 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.

36

Comparison of Year Ended December 31, 2007 to Year Ended December 31, 2006

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)
	2006		2007
Oil and gas sales (dollars in thousands)
Oil	$	117,504	$	234,428	99.5	%
Gas		131,676		131,530	(0.1	)%
Total	$	249,180	$	365,958	46.9	%
Production
Oil (MBbls)		1,906		3,356	76.1	%
Gas (MMcf)		20,949		20,504	(2.1	)%
MMcfe		32,385		40,640	25.5	%
Average sales prices (excluding hedging)
Oil per Bbl	$	61.65	$	69.85	13.3	%
Gas per Mcf		6.29		6.41	1.9	%
Mcfe	$	7.69	$	9.00	17.0	%

Oil sales increased 99.5% from $117.5 million to $234.4 million during the year ended December 31, 2007. This increase was due to a 76.1% increase in production volumes to 3,356 MBbls and a 13.3% increase in average oil prices to $69.85 per barrel. Natural gas sales revenues decreased 0.1% from $131.7 million for the year ended December 31, 2006 to $131.5 million for the year ended December 31, 2007. This decrease was due to a 2.1% decrease in production volumes to 20,504 Mmcf, partially offset by a 1.9% increase in average gas prices to $6.41 per Mcf. Oil production for the year ended December 31, 2007 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 (Decrease)
	2006	2007
Mid Continent	19,499	26,331	35.0	%
Permian Basin	5,497	6,284	14.3	%
Gulf Coast	3,348	3,787	13.1	%
Ark-La-Tex	1,724	1,905	10.5	%
North Texas	1,119	1,382	23.5	%
Rockies	1,198	951	(20.6	)%
Totals	32,385	40,640	25.5	%

The effects of hedging on our net revenues for the years ended December 31, 2006 and 2007 are as follows:

	Year ended December 31,
(dollars in thousands)	2006			2007
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(22,927	)	$	(19,797	)
Hedge ineffectiveness		18,761			(8,343	)
Total	$	(4,166	)	$	(28,140	)

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Our loss from oil and gas hedging settlements in 2007 decreased $3.1 million due to improved hedge positions in relation to commodity prices from 2007 compared to 2006. Additionally as a result of higher NYMEX forward strip oil prices at December 31, 2007 compared to December 31, 2006, hedge ineffectiveness resulted in a loss of $8.3 million in 2007 compared to a gain of $18.8 million in 2006.

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, 2006	$	61.65	$	47.32	76.8	%
Year ended December 31, 2007		69.85		59.38	85.0	%
Gas (per Mcf):
Year ended December 31, 2006	$	6.29	$	7.39	117.5	%
Year ended December 31, 2007		6.41		6.76	105.5	%

Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2006 and 2007:

	Amount						Per Mcfe
	Year ended December 31,				Percent Increase		Year ended December 31,				Percent Increase
(dollars in thousands)	2006		2007				2006		2007
Lease operating expenses	$	71,663	$	104,469	45.8	%	$	2.21	$	2.57	16.3	%
Production taxes		18,710		26,216	40.1	%		0.58		0.65	12.1	%
Depreciation, depletion and amortization		52,299		85,842	64.1	%		1.61		2.11	31.1	%
General and administrative		14,659		21,838	49.0	%		0.45		0.54	20.0	%

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 $22.3 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 $8.9 million of costs associated with workovers in 2007 compared to $9.5 million in 2006.

Production taxes (which include ad valorem taxes)—Increase was due primarily to a 26% increase in production volumes and an approximate 17% increase in prices.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $31.6 million. For oil and gas properties, $16.0 million of the increase was due to higher production volumes in 2007 and $15.6 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 $0.49 to $1.94 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses—Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. In addition, we increased our compensation plan, including an increase in our officer bonus program and decreased the vesting period related to the phantom unit plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.4 million of the increase was due to the revision in the phantom unit plan. G&A expense also includes $0.6 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $10.8 million in 2007 and $8.3 million in 2006 capitalized as part of our exploration and development activities.

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Interest expense. Interest expense increased by $42.4 million, or 93.7%, compared to 2006, primarily as a result of increased levels of borrowings and higher interest rates paid. The following table presents interest expense:

	2006		2007
Revolver Interest	$	16,372	$	27,387
8 1/2% Senior Notes, due 2015		28,223		28,285
8 7/8% Senior Notes, due 2017		—		28,413
Other Interest		651		3,571
		45,246		87,656

Non-hedge derivative losses. Non-hedge derivative losses were $23.8 million for the year ended December 31, 2007 and are comprised of losses of $24.4 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, and $0.6 million of gains related to natural gas basis differential swaps. 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.

Service company revenues and operating expenses. Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $20.6 million in service company revenue in the year ended December 31, 2007 with corresponding service company expense of $18.4 million, for a net profit of $2.2 million. Service company revenue before intercompany eliminations was $37.7 million and a pre-tax net profit of $2.7 million in the year ended December 31, 2007. There were no service company revenues or expenses during the year of 2006.

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	)%

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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	16,314	19,499	19.5	%
Permian	3,790	5,497	45.0	%
Gulf Coast	2,418	3,348	38.5	%
Ark-La-Tex	1,162	1,724	48.4	%
North Texas	817	1,119	37.0	%
Rockies	853	1,198	40.4	%
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.

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	%

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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.

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, 2007, we had approximately $11.7 million of cash and cash equivalents and $76.3 million of availability under our revolving credit line with a borrowing base of $525.0 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

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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, 2007, we incurred actual costs as summarized by area in the following table:

(Dollars in thousands)	For the year ended December 31, 2007(1)		Percent of total
Mid-Continent	$	130,430	56.7	%
Permian Basin		46,928	20.4	%
Gulf Coast		30,661	13.3	%
Ark-La-Tex		7,246	3.1	%
North Texas		7,557	3.3	%
Rocky Mountains		7,398	3.2	%
	$	230,220	100	%

(1) Includes $0.3 million of additions relating to increases in Chaparral’s asset retirement obligations.

In addition to the capital expenditures for oil and gas properties, we spent approximately $23.9 million for acquisition and construction of new office and administrative facilities and equipment during 2007.

Our actual costs incurred for the year ended December 31, 2007 and our current 2008 budgeted capital expenditures for oil and gas properties are detailed in the table below:

(Dollars in thousands)	For the year ended December 31, 2007(1)		2008 budgeted capital expenditures(3)
Development activities:
Developmental drilling	$	106,146	$	118,000
Enhancements		43,887		29,000
EOR		15,144		17,000
Acquisitions:
Proved properties(2)		41,724		30,000
Unproved properties		8,032		5,000
Exploration activities		15,287		10,000
Total	$	230,220	$	209,000

(1) Includes $0.3 million of additions relating to increases in Chaparral’s asset retirement obligations.

(2) The 2008 acquisition budget does not include an anticipated ethanol plant investment of approximately $30 to $33 million.

(3) Our current 2008 capital expenditure budget for oil and gas properties is $209.0 million assuming we receive net proceeds of $70.0 million from an issuance of our equity which we are considering during 2008.

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Our 2008 budgeted development and exploratory drilling and EOR capital expenditures summarized by area are detailed in the table below:

(Dollars in thousands)	2008 drilling capital expenditures		Percent of total
Mid-Continent	$	64,000	44	%
Permian Basin		57,000	39	%
Gulf Coast		21,000	15	%
North Texas		1,500	1	%
Other		1,500	1	%
	$	145,000	100	%

A majority of our capital expenditure budget for development drilling in 2008 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 EOR 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 2008 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, 2007, the net cash provided from operations was approximately 47% of our net cash used in investing activities. For the year ended December 31, 2007, cash flow from operating activities increased by 28% 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, 2007, we had $447.0 million outstanding under our Credit Agreement and the borrowing base was $525.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of December 31, 2007.

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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, 2006 and 2007, our current ratio as computed using generally accepted accounting principles was 0.88 and 0.69, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.15 and 1.49, 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, 2006			December 31, 2007
Current assets per GAAP	$	91,863		$	120,704
Plus—Availability under Credit Agreement		112,136			76,311
Less—Deferred tax asset on derivative instruments and asset retirement obligation		(847	)		(19,123	)
Less—Short-term derivative instruments		(7,599	)		—
Current assets as adjusted	$	195,553		$	177,892
Current liabilities per GAAP	$	104,255		$	174,980
Less—Short-term derivative instruments		(12,376	)		(54,307	)
Less—Short-term asset retirement obligation		(749	)		(1,000	)
Current liabilities as adjusted	$	91,130		$	119,673
Current ratio for loan compliance		2.15			1.49

In 2005, the Company entered into a Sixth Restated Credit Agreement, which provided for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base was determined based on reserve value, among other factors. 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 is scheduled to mature on October 31, 2010. Availability under our credit agreement is subject to a borrowing base 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. Effective November 1, 2007 the borrowing base was adjusted to $525,000. 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) and on $447,000 based upon LIBOR as of December 31, 2007 (effective rate of 7.163%). 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.

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, 2007, $447.0 million of our borrowings were Eurodollar loans.

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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, 2007, the LIBOR rate was 4.88%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.28% resulting in an effective interest rate of 7.16% 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.

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.

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

• 2.75 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007, June 30, 2007 and September 30, 2007 and for the four consecutive fiscal quarters ending on December 31, 2007; and

• 2.50 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 quarters thereafter.

We believe we were in compliance with all covenants under the Credit Agreement as of December 31, 2007.

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;

• 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.

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

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

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

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

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

• incur additional indebtedness;

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

• make investments;

• incur liens;

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

• engage in transactions with our affiliates;

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

• consolidate, merge or transfer assets.

If we experience a change of control (as defined in the indenture governing the 8 ¹/2% Senior Notes), 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, 2012, 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.

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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.

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

During September 2007, we determined that the exchange offer would not be completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $0.3 million during the year ended December 31, 2007. On February 29, 2008, we completed the exchange offer and liquidated damages ceased to accrue as of that date.

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, 2007:

(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	$	32,019	$	487,024	$	—	$	—	$	519,043
Senior notes, including estimated interest expense		56,246		112,492		112,492		873,471		1,154,701
Other long-term notes—including estimated interest expense		7,861		11,478		2,592		349		22,280
Capital leases—including estimated interest		164		19		—		—		183
Operating leases		477		43		—		—		520
Abandonment obligations		1,000		2,000		2,000		25,684		30,684
Derivative obligations		54,307		70,613		25,614		—		150,534
Total	$	152,074	$	683,669	$	142,698	$	899,504	$	1,877,945

(1) As of December 31, 2007, the Company has no off-balance sheet arrangements.

In 2006, we entered into an agreement to build a natural gas pipeline to transport gas to an ethanol plant expected to be constructed and operational in early 2008. As of December 31, 2007, the pipeline is being constructed, and the costs are currently estimated to be approximately $2.2 million.

We have long-term contracts to purchase up to all of the CO₂ manufactured at three ethanol plants. Two of the plants are operating and, based on plant capacity, it is estimated that we will purchase approximately 4.2 MMcf per day over the ten-year contract term under one contract, and under the second contract approximately 13.75 MMcf per day over the fifteen-year contract term. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. The third ethanol plant has not yet been constructed but, when constructed, we will purchase approximately 5.5 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 EOR projects. Under one contract we may purchase a variable amount of CO₂, up to 20.0 MMcf per day through July 1, 2010. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 16.0 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, and we are currently purchasing 5.0 MMcf per day and project our purchases to remain at that 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.

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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 operations. 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 operations 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.

• 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 88% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2007 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

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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 costs 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 is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

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

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

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

51

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 September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. The Company is currently assessing the impact, if any, of the adoption of SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which the Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact to its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. The Company is currently assessing the impact, if any, the adoption of SFAS No. 141(R) may have on any future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51. “ SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS 160.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133, Accounting for Derivatives and Hedging Activities, do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, this statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and

52

interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, of the adoption of SFAS 161.

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.

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, 2007 production, our gross revenues from oil and gas sales would change approximately $2.1 million for each $0.10 change in gas prices and $3.4 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.

53

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, 2007 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 2008	2,070	$	1.16	3,760	$	8.50	71.9	%	624	$	69.74	60	$	67.48	80.6	%
2Q 2008	2,220		0.81	3,720		7.83	74.1	%	600		69.59	60		67.63	79.4	%
3Q 2008	2,220		0.81	3,460		7.91	72.9	%	580		69.33	60		67.64	80.0	%
4Q 2008	2,120		0.90	3,300		8.23	73.1	%	550		69.86	74		67.41	80.6	%
1Q 2009	2,070		0.92	900		9.08	20.9	%	495		69.82	111		67.15	80.8	%
2Q 2009	540		0.82	900		8.14	21.8	%	477		68.83	90		66.94	77.6	%
3Q 2009	—		—	900		8.23	23.2	%	465		68.15	90		66.57	80.5	%
4Q 2009	—		—	900		8.59	24.1	%	456		67.58	90		66.18	81.0	%
1Q 2010	—		—	—		—	—		420		67.40	102		65.80	79.3	%
2Q 2010	—		—	—		—	—		420		67.10	90		65.47	79.4	%
3Q 2010	—		—	—		—	—		408		66.43	90		65.10	79.2	%
4Q 2010	—		—	—		—	—		402		65.95	90		64.75	79.8	%
1Q 2011	—		—	—		—	—		309		64.40	99		64.24	68.8	%
2Q 2011	—		—	—		—	—		309		64.06	90		63.93	68.7	%
3Q 2011	—		—	—		—	—		309		63.71	90		63.61	70.2	%
4Q 2011	—		—	—		—	—		309		63.33	90		63.30	71.5	%
	11,240			17,840					7,133			1,376

(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, 2007, we entered into additional natural gas swaps for 2,160 MMcf for the periods of February 2008 through December 2009 at a weighted average price of $8.19. We also entered into additional crude oil swaps for 110 MBbl for the periods of March 2008 through December 2009 at a weighted average price of $90.41.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of December 31, 2007 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $525.0 million, equal to our borrowing base at December 31, 2007, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.25 million.

54

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	56
Consolidated balance sheets as of December 31, 2006 and 2007	57
Consolidated statements of operations for the years ended December 31, 2005, 2006 and 2007	58
Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2005, 2006 and 2007	59
Consolidated statements of cash flows for the years ended December 31, 2005, 2006 and 2007	60
Notes to consolidated financial statements	62

55

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, 2006 and 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2007. 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, 2006 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/    GRANT THORNTON LLP        

Oklahoma City, Oklahoma

March 31, 2008

56

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	December 31,
(dollars in thousands, except share data)	2006			2007
Assets
Current assets:
Cash and cash equivalents	$	8,803		$	11,687
Accounts receivable, net		62,728			66,105
Inventories		7,505			19,480
Deferred income taxes		968			19,128
Prepaid expenses		4,260			4,304
Derivative instruments		7,599			—
Total current assets		91,863			120,704
Property and equipment—at cost, net		31,809			50,747
Oil & gas properties, using the full cost method:
Proved		1,254,230			1,477,096
Unproved (excluded from the amortization base)		18,299			25,327
Accumulated depreciation, depletion and amortization		(121,859	)		(200,577	)
Total oil & gas properties		1,150,670			1,301,846
Funds held in escrow		23,385			5,224
Other assets		33,708			52,377
	$	1,331,435		$	1,530,898
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	67,997		$	77,540
Accrued interest payable		3,078			14,741
Revenue distribution payable		17,249			21,471
Current maturities of long-term debt and capital leases		3,555			6,921
Derivative instruments		12,376			54,307
Total current liabilities		104,255			174,980
Long-term debt and capital leases, less current maturities		647,717			459,826
8 1/2% Senior Notes, due 2015		325,000			325,000
8 7/8% Senior Notes, due 2017		—			322,490
Derivative instruments		2,300			96,227
Deferred compensation		771			2,017
Asset retirement obligations		27,377			29,684
Deferred income taxes		46,151			17,496
Commitments and contingencies (note 14)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2006 and 2007, respectively		9			9
Additional paid in capital		100,918			100,918
Retained earnings		80,883			76,090
Accumulated other comprehensive loss, net of taxes		(3,946	)		(73,839	)
		177,864			103,178
	$	1,331,435		$	1,530,898

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

57

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Year Ended December 31,
(dollars in thousands, except share and per share amounts)	2005			2006			2007
Revenues:
Oil and gas sales	$	201,410		$	249,180		$	365,958
Loss from oil and gas hedging activities		(68,324	)		(4,166	)		(28,140	)
Service company sales		—			—			20,611
Total revenues		133,086			245,014			358,429
Costs and expenses:
Lease operating		42,147			71,663			104,469
Production tax		14,626			18,710			26,216
Depreciation, depletion and amortization		31,423			52,299			85,842
General and administrative		9,808			14,659			21,838
Service company expenses		—			—			18,441
Total costs and expenses		98,004			157,331			256,806
Operating income		35,082			87,683			101,623
Non-operating income (expense):
Interest expense		(15,588	)		(45,246	)		(87,656	)
Non-hedge derivative losses		—			(4,677	)		(23,781	)
Other income		665			792			2,276
Net non-operating expense		(14,923	)		(49,131	)		(109,161	)
Income (loss) before income taxes and minority interest		20,159			38,552			(7,538	)
Income tax expense (benefit)		7,309			14,817			(2,745	)
Minority interest		—			(71	)		—
Net income (loss)	$	12,850		$	23,806		$	(4,793	)
Net income (loss) per share (basic and diluted)	$	16.58		$	29.74		$	(5.47	)
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			800,500			877,000

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

and comprehensive income (loss)

(dollars in thousands)	Members’ units/ Common Stock				Additional Paid In Capital		Undistributed/ Retained earnings			Accumulated other comprehensive income (loss)			Total
	Units/Shares		Amount
Balance at January 1, 2005	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 income (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 (loss), 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
Net loss	—			—		—		(4,793	)		—			(4,793	)
Other comprehensive income (loss), net
Unrealized loss on hedges, net of taxes of $51,745	—			—		—		—			(82,032	)		(82,032	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $7,658	—			—		—		—			12,139			12,139
Total comprehensive loss														(74,686	)
Balance at December 31, 2007	877,000		$	9	$	100,918	$	76,090		$	(73,839	)	$	103,178

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Year Ended December 31,
(dollars in thousands)	2005			2006			2007
Cash flows from operating activities
Net income (loss)	$	12,850		$	23,806		$	(4,793	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		31,423			52,299			85,842
Deferred income taxes		7,637			14,839			(2,729	)
Unrealized (gain) loss on ineffective portion of hedges		14,740			(18,761	)		8,343
Non-cash change in fair value of derivative instruments		—			4,681			23,781
Gain on sale of assets		(231	)		(132	)		(712	)
Other		162			1,151			1,243
Change in assets & liabilities, net of assets and liabilities of business acquired
Accounts receivable		(7,979	)		(13,213	)		(13,635	)
Inventories		(2,961	)		(329	)		3,704
Prepaid expenses and other assets		(270	)		376			(1,079	)
Accounts payable and accrued liabilities		4,784			16,659			8,426
Revenue distribution payable		(4,936	)		7,696			4,221
Deferred compensation		525			126			1,246
Net cash provided by operating activities		55,744			89,198			113,858
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(170,570	)		(201,300	)		(221,066	)
Acquisition of a business, net of cash acquired		(113,622	)		(466,656	)		(21,569	)
Payment on non-hedge derivative transactions assumed in acquisition of a business		(42,108	)		—			—
Cash in escrow		—			(21,795	)		(2,156	)
Proceeds from dispositions of property and equipment and oil and gas properties		1,202			5,820			526
Proceeds from sale of a business		—			—			3,158
Purchase of prepaid production tax asset		—			(15,000	)		—
Other		30			(4,917	)		1,250
Net cash used in investing activities		(325,068	)		(703,848	)		(239,857	)
Cash flows from financing activities
Proceeds from long-term debt		122,676			629,936			119,865
Repayment of long-term debt and acquisition financing		(309,383	)		(100,199	)		(304,240	)
Proceeds from equity issuance		—			100,919			—
Proceeds from acquisition financing		132,000			—			—
Proceeds from senior notes		325,000			—			322,329
Principal payments under capital lease obligations		(442	)		(148	)		(171	)
Dividends		(3,409	)		(1,049	)		—
Settlement of derivative instruments acquired		—			876			(1,898	)
Fees paid related to financing activities		(9,195	)		(8,107	)		(7,002	)
Fees paid related to IPO activities		(167	)		(373	)		—
Net cash provided by financing activities		257,080			621,855			128,883
Net increase (decrease) in cash and cash equivalents		(12,244	)		7,205			2,884
Cash and cash equivalents at beginning of period		13,842			1,598			8,803
Cash and cash equivalents at end of period	$	1,598		$	8,803		$	11,687
Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	12,590		$	44,068		$	73,822
Income taxes		(328	)		(22	)		(16)

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(continued)

Supplemental disclosure of noncash investing and financing activities

During the years ended December 31, 2005, 2006, and 2007 the Company entered into capital lease obligations of $70, $140, and $21, respectively, for machinery and equipment.

During the years ended December 31, 2005, 2006 and 2007, the Company recorded non-cash additions to oil and gas properties of $9,367, $7,317 and $24,527, respectively. Non cash additions to oil and gas properties in 2007 includes $15,597 related to final settlement of the Calumet acquisition.

During the years ended December 31, 2005, 2006, and 2007, the Company recorded an asset and related liability of $4,680, $10,813 and $266, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $3 was capitalized during the year ended December 31, 2005 primarily related to the construction of the Company’s office building and other construction projects. Interest of $1,001 and $1,613 was capitalized during the years ended December 31, 2006 and 2007, respectively, primarily related to unproved oil and gas leaseholds.

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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 operations. 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.

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, valuation allowances associated with 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, 2006 and 2007 were $1,034 and $1,060, 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.

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The Company writes off accounts receivable when they are determined to be uncollectible. Bad debt expense (recovery) for the years ended December 31, 2005, 2006, and 2007 was $140, $553, and $(11), 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:

	2006			2007
Joint interests	$	13,771		$	19,319
Accrued oil and gas sales		32,763			40,377
Service company sales		—			4,827
Receivable from purchase price adjustment		14,406			—
Other		2,084			1,920
Allowance for doubtful accounts		(296	)		(338	)
	$	62,728		$	66,105

Inventories

Inventories are comprised of equipment used in developing oil and gas properties, oil and gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the specific identification method and average cost method, respectively. Oil and gas product inventories are stated at the lower of production cost or market. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory if necessary. Inventories at December 31, 2006 and 2007 consist of the following:

	December 31, 2006		December 31, 2007
Equipment inventory	$	4,832	$	3,027
Oil and gas product		2,673		3,221
Service company inventory for resale		—		13,232
	$	7,505	$	19,480

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

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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 $27,650, $47,086, and $78,717 for the years ended December 31, 2005, 2006, and 2007, respectively.

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

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 are 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. As of December 31, 2006, and 2007, the carrying value of the production tax benefit assets was $15,000 and $14,255, respectively, and was included in other assets in the consolidated balance sheets. Of the $1,490 received in 2007, $745 was recognized as income and $745 as a reduction of the asset.

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		2007
Title defect escrow from acquisition	$	21,795	$	383
Plugging and abandonment escrow		1,590		1,635
Post closing adjustment escrow from acquisition		—		3,206
	$	23,385	$	5,224

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

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

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Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long lived assets 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.

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

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized no material adjustment in our tax liability for unrecognized income tax benefits. At the adoption date of January 1, 2007, we had approximately $100 of unrecognized tax benefits, all of which would affect our effective tax rate if recognized. At December 31, 2007, the unrecognized tax benefit amount was unchanged from adoption.

If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2007, we have not accrued interest related to uncertain tax positions.

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

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. Service company sales are recognized at the time of delivery of materials or performance of service.

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

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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 1,866,000 thousand cubic feet (mcf), 1,903,000 mcf, and 1,961,000 mcf at December 31, 2005, 2006, and 2007, respectively. The Company’s aggregate imbalance due to under production is approximately 3,313,000 mcf, 3,331,000 mcf, and 3,170,000 mcf at December 31, 2005, 2006, and 2007, 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 2005, 2006, or 2007. The ineffective portions of derivative gains or losses are reported in loss from oil and gas hedging activities on the consolidated statements of operations.

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 operations. 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, 2006 and 2007, 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.

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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 September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted. However, in February, 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This FSP partially defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, and interim periods within those fiscal years for items within the scope of this FSP. The Company is currently assessing the impact, if any, of the adoption of SFAS 157.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” SFAS No. 159 permits companies to choose to measure certain financial instruments and other items at fair value. The objective is to improve financial reporting by providing companies with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Unrealized gains and losses on any items for which the Company elects the fair value measurement option would be reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact on its consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. The Company is currently assessing the impact, if any, the adoption of SFAS No. 141(R) may have on any future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51. “ SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. The Company is currently assessing the impact, if any, of the adoption of SFAS 160.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133, Accounting for

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Derivatives and Hedging Activities, do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, this statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Company is currently assessing the impact, if any, of the adoption of SFAS 161.

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. 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 statements of operations 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 EOR opportunities.

Pursuant to the purchase agreement with Calumet, the Company estimated and recorded a receivable of $14,412 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, and is included in other assets as of December 31, 2007. 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, 2007, the escrow balance was $383 for defects yet to be cleared.

As part of the purchase, the previous owners of Calumet agreed to make a Section 338 election pursuant to the Internal Revenue Code, and the Company agreed to reimburse the owners for the amount of depreciation recapture recorded. As of December 31, 2007, the Company has recorded an estimated liability of $4,378 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 accompanying consolidated balance sheets.

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

At the closing date of the sale, the Company withheld and deposited into escrow $5,029 of the purchase price for certain working capital, environmental and employment adjustments. Pursuant to the agreement, upon settlement of the various requirements, the amount in escrow will be disbursed. If the requirements are not met, the amount escrowed will be returned to the Company. As of December 31, 2007, $3,206 remained in escrow.

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The acquisition was accounted for using the purchase method in accordance with the provisions of SFAS No. 141, Business Combinations. The purchase price allocation of the GCS acquisition is preliminary and subject to additional adjustments. The Company expects to complete the final allocation in the next 6 months. The calculation of the purchase price and the allocation to assets and liabilities are shown below.

	GCS
Calculation and allocation of purchase price:
Cash payment	$	25,000
Cash deposited in escrow		(3,083	)
Total purchase price		21,917
Plus fair value of liabilities assumed:
Accounts payable and accrued expenses		5,242
Total purchase price plus liabilities assumed	$	27,159
Fair value of assets acquired:
Current assets, including cash of $348	$	23,307
Property and equipment		3,016
Intangible assets		836
Total fair value of assets acquired	$	27,159

The intangible assets primarily consist of fair value of customer lists which are being amortized over 84 months.

The unaudited pro forma information of the Company set forth below includes the operations of GCS for years ended December 31, 2006 and 2007 as if the acquisition occurred on January 1, 2006. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

	Year ended December 31, 2006				Year ended December 31, 2007
(dollars in thousands, except per share data)	As reported		Pro forma		As reported			Pro forma
Revenue	$	245,014	$	278,415	$	358,429		$	366,786
Net income (loss)	$	23,806	$	26,079	$	(4,793	)	$	(4,551	)
Net income (loss) per share (basic and diluted)	$	29.74	$	32.58	$	(5.47	)	$	(5.19	)

Note 3: Property and equipment

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

	2006		2007
Furniture and fixtures	$	1,132	$	1,437
Automobiles and trucks		8,807		11,559
Machinery and equipment		11,288		19,253
Office and computer equipment		5,303		6,006
Building and improvements		12,074		13,532
		38,604		51,787
Less accumulated depreciation and amortization		10,813		14,622
		27,791		37,165
Work in progress		1,446		8,552
Land		2,572		5,030
	$	31,809	$	50,747

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

	2006		2007
Office and computer equipment	$	1,762	$	1,783
Machinery and equipment		82		82
		1,844		1,865
Less accumulated depreciation and amortization		1,312		1,675
	$	532	$	190

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.

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

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

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

	December 31,
	2006			2007
Derivative assets (liabilities):
Gas swaps	$	10,118		$	4,709
Oil swaps		(16,349	)		(155,782	)
Natural gas basis differential swaps		(846	)		539
	$	(7,077	)	$	(150,534	)

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

	Year ended December 31,
	2005			2006			2007
Reclassification of settled contracts	$	(53,584	)	$	(22,927	)	$	(19,797	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		(14,740	)		18,761			(8,343	)
	$	(68,324	)	$	(4,166	)	$	(28,140	)

Based upon market prices at December 31, 2007 the Company expects to charge $29,033 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, 2007 are expected to be settled by December 2011.

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

	Year Ended December 31,
	2006			2007
Unrealized loss on non-qualified derivative contracts	$	(3,746	)	$	(24,416	)
Unrealized gain (loss) on natural gas basis differential contracts		(846	)		1,385
Loss on settlement of natural gas basis differential contracts		(85	)		(750	)
	$	(4,677	)	$	(23,781	)

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Hedge settlement payments of $3,444, and $8,759 were included in accounts payable and accrued liabilities at December 31, 2006 and 2007, respectively. Hedge settlement receivables of $759 and $51 were included in accounts receivable at December 31, 2006 and 2007, respectively.

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 and capital leases at December 31, 2006 and 2007 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. Based on market prices, at December 31, 2007, the fair value of the 8 ¹/2% Senior Notes and 8 ⁷/8% Senior Notes were $291,688 and $293,313, respectively.

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

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 14.3% and 11.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the years ended December 31, 2005 and 2006, respectively. Sales of oil and natural gas to two purchasers accounted for 18.1% and 12.0% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2007. If the Company were to lose a purchaser, we believe we could replace it with a substitute purchaser.

Note 5: Asset retirement obligations

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

	As of December 31,
	2006			2007
Beginning balance	$	15,796		$	28,126
Liabilities incurred in current period		715			266
Liabilities acquired		9,342			—
Liabilities settled in current period		(256	)		(99	)
Accretion expense		1,773			2,391
Revisions of estimated cash flows		756			—
Ending ARO balance		28,126			30,684
Less current portion		749			1,000
	$	27,377		$	29,684

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Note 6: Long-term debt

Long-term debt consists of the following:

	December 31,
	2006		2007
Revolving credit line with banks(1)	$	637,000	$	447,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 5.00% to 7.283%, due December 2008 through September 2021; collateralized by real property		7,036		9,644
Installment note payable, principal and interest payable quarterly in varying amounts, non-interest-bearing (discounted at 5.6% at December 31, 2006 and 2007), due December 2007		837		—
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 9.387%, due January 2008 through September 2012; collateralized by automobiles, machinery and equipment		5,821		9,925
		650,944		466,569
Less current maturities		3,392		6,762
	$	647,552	$	459,807

(1) In 2005, the Company entered into a Sixth Restated Credit Agreement, which provided for a revolving credit line equal to the lesser of $450,000 or the borrowing base. The borrowing base was determined based on reserve value, among other factors. 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 is scheduled to mature on October 31, 2010. Availability under our credit agreement is subject to a borrowing base 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. Effective November 1, 2007 the borrowing base was adjusted to $525,000. 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) and on $447,000 based upon LIBOR as of December 31, 2007 (effective rate of 7.163%). 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.

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

• 2.75 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarter ending on March 31, 2007, June 30, 2007 and September 30, 2007 and for the four consecutive fiscal quarters ending on December 31, 2007; and

• 2.50 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 quarters thereafter.

We believe we were in compliance with all covenants under the Credit Agreement as of December 31, 2007.

(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

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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.

Maturities of long-term debt as of December 31, 2007 are as follows:

2008	$	6,762
2009		2,966
2010		454,123
2011		1,638
2012		783
2013 and thereafter		297
	$	466,569

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, 2007 are as follows:

2008	$	164
2009		19
2010		—
Total minimum lease payments		183
Less amount representing interest		5
Present value of net minimum lease payments		178
Less current portion		159
	$	19

Note 8: Senior Notes

Issuance of our 8 ¹/2 % Senior Notes due 2015. On December 1, 2005, the Company issued $325,000 of 8.5% senior notes due 2015 at a price of 100% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to repay the $132,000 bridge loan facility with General Electric Capital Corporation and to pay down debt under our revolving credit line.

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

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

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

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

• make investments;

• create liens on assets;

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• 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 $8,604 and $7,943 as of December 31, 2006 and 2007, respectively, that are included in other assets. Amortization of $598 and $660 was charged to interest expense during the years ended December 31, 2006 and 2007, respectively, related to these costs.

Issuance of our 8 ⁷/8% Senior Notes due 2017. On January 18, 2007, the Company issued $325,000 of 8.875% senior notes due 2017 at a price of 99.178% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to reduce outstanding indebtedness under our revolving line of credit and for working capital.

Interest is payable on the senior notes semi-annually on February 1 and August 1 each year beginning August 1, 2007. The senior notes mature on February 1, 2017. On or after February 1, 2012, the Company, at its option, may redeem the senior notes at the following redemption prices plus accrued and unpaid interest: 104.49% after February 1, 2012, 102.96% after February 1, 2013, 101.48% after February 1, 2014, and 100% after February 1, 2015 and thereafter. Prior to February 1, 2012, the Company may redeem up to 35% of the senior notes with the net proceeds of one or more equity offerings at a redemption price of 108.88%, plus accrued and unpaid interest.

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

• 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 our 8 ⁷/ 8% senior notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for other freely tradable notes and complete such exchange offer within 270 days of the issue date. If we fail to complete the exchange offer within 270 days after the issue date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

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During September 2007, we determined that the exchange offer would not be completed within the 270 day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $339 during the year ended December 31, 2007. On February 29, 2008, we completed the exchange offer and liquidated damages ceased to accrue as of that date.

In connection with the issuance of the 8 ⁷/8% senior notes, the Company recorded a discount of $2,671 and capitalized $7,201 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized issuance costs of $6,770 as of December 31, 2007 that are included in other assets. Amortization of $161 and $431 was charged to interest expense during the year ended December 31, 2007 related to the discount and issuance costs, respectively.

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

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

	December 31,
	2006		2007
8.5% Senior Notes due 2015	$	325,000	$	325,000
8.875% Senior Notes due 2017		—		325,000
Discount on Senior Notes		—		(2,510	)
	$	325,000	$	647,490

Note 9: Income taxes

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

	2005			2006			2007
Current tax benefit	$	(328	)	$	(22	)	$	(16	)
Deferred tax expense (benefit)		7,637			14,839			(2,729	)
	$	7,309		$	14,817		$	(2,745	)

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

	2005		2006		2007
Statutory rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	3.6	%	3.6	%	3.6	%
Statutory depletion	(1.0	)%	(0.5	)%	(0.5	)%
Other	(1.3	)%	0.3	%	(1.7	)%
Effective tax rate	36.3	%	38.4	%	36.4	%

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

	2006			2007
Deferred tax assets related to
Derivative instruments	$	2,489		$	48,691
Asset retirement obligations		2,035			2,981
Accrued expenses, allowance and other		1,619			2,346
Net operating loss carryforwards
Federal		12,159			30,771
State		7,194			12,657
Statutory depletion carryforwards		1,387			1,434
Alternative minimum tax credit carryforwards		204			204
		27,087			99,084
Less: valuation allowance		4,675			7,999
		22,412			91,085
Deferred tax liabilities related to
Derivative instruments		(1,113	)		—
Property and equipment		(65,448	)		(88,865	)
Inventories		(1,034	)		(588	)
		(67,595	)		(89,453	)
Net deferred tax assets (liabilities)	$	(45,183	)	$	1,632

Approximately $1,705 and $18,736 of the current deferred tax asset at December 31, 2006 and 2007, respectively, relates to the short-term derivative instruments. Additionally, approximately $54 and $387 of the current deferred tax asset relates to asset retirement obligations at December 31, 2006 and 2007, respectively. At December 31, 2006 and 2007, taxes receivable of $7 and $74, respectively, are included in accounts receivable.

The Company has federal net operating loss carryforwards of approximately $88,000 at December 31, 2007, which will begin to expire in 2008 if unused, of which significant amounts begin to expire in 2018. At December 31, 2007, the Company has state net operating loss carryforwards of approximately $224,000, which will begin to expire in 2008. At December 31, 2007, approximately $141,000 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, 2007, the Company had tax percentage depletion carryforwards of approximately $4,098 which are not subject to expiration.

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Note 10: Segment Information

In accordance with SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, we have two reportable operating segments. Our exploration and production segment and service company segment are managed separately because of the nature of their products and services. The exploration and production segment is responsible for finding and producing oil and natural gas. The service company segment is responsible for selling oilfield services and supplies. Management evaluates the performance of our segments based upon income before taxes. The service company was acquired during the second quarter of 2007, therefore, no segment information is provided for the year ended December 31, 2006 or 2005.

	Exploration and Production			Service Company			Intercompany Eliminations			Consolidated Total
For the Year Ended December 31, 2007:
Revenues	$	337,818		$	37,717		$	(17,106	)	$	358,429
Intersegment revenues		—			(17,106	)		17,106			—
Total revenues		337,818			20,611			—			358,429
Income (loss) before income taxes	$	(9,708	)	$	2,740			(570	)	$	(7,538	)
As of December 31, 2007:
Total assets	$	1,529,452		$	28,092		$	(26,646	)	$	1,530,898

Note 11: Related party transactions

On December 7, 2007, our board of directors approved the sale of Pointe Vista Development, L.L.C., an indirect, wholly owned subsidiary of the Company, to Fischer Investments, L.L.C., an Oklahoma limited liability company controlled by Mark A. Fischer, our Chairman, Chief Executive Officer and President, for approximately $3.2 million resulting in a gain on the sale of $591. The sale of this non-core asset was approved by our board of directors in an effort to focus on our core business areas of oil and gas production and exploitation.

In 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, and $8,028 and $4,107, respectively for the year ended December 31, 2007 on these properties. In addition, Chesapeake participates in ownership of properties operated by the Company. During the year ended December 31, 2006, the Company paid revenues and recorded joint interest billings of $1,809 and $2,556, respectively to Chesapeake. During the year ended December 31, 2007, the Company paid revenues and recorded joint interest billings of $1,409 and $1,552, respectively to Chesapeake. There were no significant amounts receivable or payable to Chesapeake at December 31, 2007.

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

Note 12: 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

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total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Under the original plan, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Payment is not required by the participant upon redemption. Effective January 1, 2007 the Company reduced the phantom unit vest period from the seventh anniversary of the award date to the fifth anniversary of the award date for all employees in the plan. In accordance with SFAS No. 123(R) “Share Based Payments”, the reduction in the vesting period is accounted for as a modification to the plan and is accounted for on a prospective basis. The Company recorded additional deferred compensation expense of $417 during the year ended December 31, 2007 as a result of the modification.

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.

Compensation expense is recognized over the vesting period of the phantom units and is reflected in general and administrative expenses in the consolidated statements of operations. 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 $525, $128 and $1,246 for the years ended December 31, 2005, 2006 and 2007, respectively.

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

	Fair Value		Phantom Units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per share)				(Years)
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

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	Fair Value		Phantom Units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per share)				(Years)
Unvested and total outstanding at December 31, 2006	$	14.29	160,038
Granted	$	16.54	47,643
Vested	$	16.54	(77	)
Forfeited	$	16.54	(6,761	)
Unvested and total outstanding at December 31, 2007	$	16.54	200,843		2.15	$	3,322

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, 2007.

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

	Year ended December 31, 2006		Year ended December 31, 2007
Dividend yield	0.0	%	0.0	%
Volatility	75.0	%	114.0	%
Risk-free interest rate	4.7	%	3.5	%
Expected life (in years)	4.00-6.00		1.00-4.50

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, 2007, there was approximately $1,305 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 2.15 years.

Note 13: 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 6% of each employee’s gross wages. At December 31, 2005, 2006 and 2007, there were 256, 415 and 613 employees, respectively, participating in the plan. Contributions recognized by the Company totaled $682, $883 and $1,720 for the years ended December 31, 2005, 2006 and 2007, respectively.

Note 14: Commitments and contingencies

Standby Letters of Credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. The Company had various Letters outstanding totaling $990, $865, and $1,690 as of December 31, 2005, 2006, and 2007, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 8.25% at December 31, 2006 and 7.163% at December 31, 2007) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during 2005, 2006, or 2007.

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, 2005, 2006, and 2007 was $2,725, $3,446, and $6,492, respectively. Future minimum rental payments for the rental of equipment on oil and gas properties are approximately $477 and $43 for the years ended December 31, 2008 and 2009, respectively.

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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 50 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 EOR 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. Company expenditures at December 31, 2007 were $2.3 million. The Company expects Oklahoma Ethanol L.L.C. will receive between $69 million to $75 million in secured indebtedness with recourse limited to the Company’s interests in this entity to fund construction costs and for related start-up working capital. The Company expects to commence construction in 2008 with completion in 2010, and that its equity contribution will be approximately $30 million to $33 million.

In 2006, we entered into an agreement to build a natural gas pipeline to transport gas to an ethanol plant expected to be constructed and operational in early 2008. As of December 31, 2007, the pipeline is being constructed, and the costs are currently estimated to be approximately $2.2 million.

We have long-term contracts to purchase up to all of the CO₂ manufactured at three ethanol plants. Two of the plants are operating and, based on plant capacity, it is estimated that we will purchase approximately 4.2 MMcf per day over the ten-year contract term under one contract, and under the second contract approximately 13.75 MMcf per day over the fifteen-year contract term. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. The third ethanol plant has not yet been constructed but, when constructed, we will purchase approximately 5.5 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 EOR projects. Under one contract we may purchase a variable amount of CO₂, up to 20.0 MMcf per day through July 1, 2010. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase approximately 16.0 MMcf per day over the remainder of the term of the contract. We may also purchase a variable amount of CO₂ under the second contract, up to 10.0 Mmcf per day through August 23, 2016, and we are currently purchasing 5.0 MMcf per day and project our purchases to remain at that 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. In addition, during 2007 the Company entered into change of control severance agreements to which the officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a 24-month period and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to his termination date, plus (B) the officer’s target bonus for the full year in which the termination date occurred or, if no target bonus has been established, then the most recent bonus paid.

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

Pursuant to the securities purchase agreement dated September 16, 2006, as amended, relating to the acquisition of Calumet, the Company recorded a receivable due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, the Company received a communication from the sellers disputing the calculation of the purchase price adjustment. The Company believes the receivable was calculated in accordance with the securities purchase agreement and intends to diligently defend its position. On September 13, 2007, the Company filed a petition in the District Court of Tulsa County, State of Oklahoma, against the John Milton Graves Trust u/t/a 6/11/2004 , et al, seeking a declaratory judgment confirming this position. As of December 31, 2007, the recorded receivable was $14,412 and was included in other assets on the consolidated balance sheet.

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Note 15: 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 sold 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 16: 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:

	2005		2006		2007
Property acquisition costs
Proved properties(1)	$	216,742	$	484,404	$	41,724
Unproved properties		5,543		4,731		8,032
Total acquisition costs		222,285		489,135		49,756
Development costs		103,479		170,987		165,177
Exploration costs		7,274		7,015		15,287
Total	$	333,038	$	667,137	$	230,220

(1) Includes $152,945 of costs related to the acquisition of CEI Bristol in 2005, $464,860 of costs related to the acquisition of Calumet in 2006 and $15,597 of amounts disbursed from escrow related to title defects and other purchase price allocation adjustments on the Calumet Acquisition in 2007.

The average depreciation, depletion and amortization rate per equivalent unit of production (mcfe) was $1.09, $1.45 and $1.94 for the years ended December 31, 2005, 2006 and 2007, 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 $25,327 of unproved property costs at December 31, 2007 being excluded from the amortization base, $6,232, $7,696 and $9,936 were incurred in 2005, 2006 and 2007, respectively, and $1,463 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 17: Disclosures about oil and gas activities (unaudited)

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

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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, 2005, 2006 and 2007 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2005	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	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	88,378		375,311		905,579
Purchase of minerals in place	1,370		10,630		18,850
Sales of minerals in place	—		(423	)	(423	)
Extensions and discoveries	7,139		43,954		86,788
Revisions	(864	)	(23,500	)	(28,684	)
Improved recoveries	6,437		6,801		45,423
Production	(3,356	)	(20,504	)	(40,640	)
Balance at December 31, 2007	99,104		392,269		986,893
Proved developed reserves:
December 31, 2005	23,762		283,173		425,745
December 31, 2006	57,824		281,958		628,902
December 31, 2007	61,567		269,578		638,980

(1) The downward revision in our gas reserves during 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;

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• 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:

	2005			2006			2007
Future cash flows	$	5,537,226		$	7,239,850		$	11,718,944
Future production costs		(1,599,503	)		(3,144,707	)		(4,600,663	)
Future development and abandonment costs		(340,423	)		(577,123	)		(914,561	)
Future income tax provisions		(1,212,513	)		(953,794	)		(2,017,915	)
Net future cash flows		2,384,787			2,564,226			4,185,805
Less effect of 10% discount factor		(1,316,899	)		(1,482,017	)		(2,391,825	)
Standardized measure of discounted future net cash flows	$	1,067,888		$	1,082,209		$	1,793,980

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 $44,935, $6,729, and $145,373 in 2005, 2006 and 2007, respectively.

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

	2005			2006			2007
Beginning of year	$	514,041		$	1,067,888		$	1,082,209
Sale of oil and gas produced, net of production costs		(144,637	)		(158,361	)		(235,273	)
Net changes in prices and production costs		477,828			(472,700	)		918,714
Extensions and discoveries		83,727			52,366			275,720
Improved recoveries		68,467			6,538			162,841
Changes in future development costs		(140,394	)		27,917			(138,791	)
Development costs incurred during the period that reduced future development costs		8,456			30,989			4,978
Revisions of previous quantity estimates		(25,195	)		(137,268	)		(83,894	)
Purchases and sales of reserves in place, net		496,645			408,000			44,869
Accretion of discount		78,483			161,752			149,406
Net change in income taxes		(276,722	)		140,413			(462,311	)
Changes in production rates and other		(72,811	)		(45,325	)		75,512
End of year	$	1,067,888		$	1,082,209		$	1,793,980

Average prices in effect at December 31, 2005, 2006 and 2007 used in determining future net revenues related to the standardized measure calculation are as follows:

	2005		2006		2007
Oil (per Bbl)	$	61.04	$	61.06	$	96.01
Gas (per Mcf)	$	10.08	$	5.64	$	6.80

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors. Based on their evaluation as of the end of the fiscal year ended December 31, 2007, 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 and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting

Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers, or persons performing similar functions, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

• pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of our management and Directors; and

• provide reasonable assurance regarding prevention or the timely detection of unauthorized acquisition, or the use or disposition of our assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2007.

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This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2007 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time in the future.

ITEM 9B. OTHER INFORMATION

None.

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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. Mark A. Fischer and Joseph O. Evans are full-time employees. We currently have no Board committees.

Name	Age	Position
Mark A. Fischer	58	Chairman, Chief Executive Officer and President
Joseph O. Evans	53	Chief Financial Officer and Executive Vice President and Director
Robert W. Kelly II	50	Senior Vice President and General Counsel
Larry E. Gateley	58	Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	44	Senior Vice President—Operations and Production Engineering
Charles A. Fischer, Jr.	59	Director

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

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

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

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

Charles A. Fischer, Jr., Director and Co-Founder, co-founded Chaparral in 1988, and served as its Chief Administrative Officer and Executive Vice President from July 2005 until his retirement effective July 27, 2007. Mr. Fischer joined Chaparral full-time in 2000 and served as its Chief Financial Officer and Senior Vice President for five years until assuming the role of Chief Administrative Officer. In 1978 Mr. Fischer founded C.A. Fischer Lumber Co. Ltd., which owns eight retail building supply outlets in western Canada, and is the current President. Mr. Fischer also serves as manager of Altoma Energy GP. Mr. Fischer began his career with Renewable Resources in 1974 as a senior scientist on the Polar Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south-central Canada. Mr. Fischer served as 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).

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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 oversee 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.

(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.

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(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.

In setting the base salary of the Senior Executives for fiscal year 2007, 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.

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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 2007 are shown in the Summary Compensation Table in this annual report.

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. The entire 2006 and 2007 annual profit sharing bonus was paid in cash in December 2006 and 2007, respectively.

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 was paid April 2, 2007.

The 2007 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 to the PEO and the NEOs for fiscal year 2007 are shown in the Summary Compensation Table in this annual report. The bonus was awarded in November 2007 and is scheduled to be paid on April 2, 2008.

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 fifth anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with us due to death, disability, retirement or termination by Chaparral without cause. Also, phantom units vest if a change of control event occurs. A change of control event will occur under the Plan if (1) our stockholders as of January 1, 2004, the date of the creation of the Phantom Unit Plan, collectively sell a

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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 94. Additional information on the phantom unit awards is shown in the Outstanding Awards at Fiscal Year-End Table in this annual report.

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.

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.

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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. Prior to January 1, 2007 the employee contributions were 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 100% vested at June 30, 2007. Mr. Miller may terminate his employment with us at any time on or after July 1, 2007, without any part of the overriding royalty interest granted reverting to us. In 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, the entire overriding royalty interest granted is 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 2007 is included in the Summary Compensation Table in this annual report.

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

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$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 obtained 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

Joseph O. Evans

Charles A. Fischer

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2007 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, and 2007.

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards(4) ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation(3) ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)			Total ($)
Mark A. Fischer, Chief Executive Officer and President	2007 2006	$	457,539 351,258	400,000 245,165	(1) (2)	—   —	—   —	400,000 —	—   —	$	17,339 20,688	(5) (5)	$	1,274,878 617,111
Joseph O. Evans, Chief Financial Officer and Executive Vice President	2007 2006		264,193 227,285	192,000 90,369	(1) (2)	—   7,514	—   —	192,000 —	—   —		16,257 13,104	(5) (5)		664,450 338,272
Charles A. Fischer, Former Chief Administrative Officer and Director	2007 2006		125,193 207,650	—   89,290	(2)	—   —	—   —	—   —	—   —		8,229 19,719	(5) (5)		133,422 316,659
Larry E. Gateley, Senior Vice President—Reservoir Engineering and Acquisitions	2007 2006		222,654 189,362	144,000 72,727	(1) (2)	—   15,010	—   —	144,000 —	—   —		15,866 11,530	(5) (5)		526,520 288,629
James M. Miller, Senior Vice President— Operations and Production Engineering	2007 2006		211,346 170,885	137,000 67,463	(1) (2)	—   15,010	—   —	137,000 —	—   —		149,744 99,514	(6) (6)		635,090 352,872
Robert W. Kelly II, Senior Vice President and General Counsel	2007		211,346	137,000	(2)	15,010	—	137,000	—		13,040	(5)		513,396

(1) Includes amounts paid under the 2007 Officers Annual Bonus that is scheduled to be paid on April 2, 2008. The amounts of unpaid Officers Annual Bonuses at December 31, 2007 were $400,000, $192,000, $144,000, $137,000 and $137,000 for Messrs. Mark A. Fischer, Joseph O. Evans, Larry E. Gateley, James M. Miller, and Robert W. Kelly II, respectively.

(2) 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 was 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.

(3) Includes amounts for 2007 that was paid on January 2, 2008. The officers were awarded cash payments in lieu of receiving restricted stock since the Company’s common stock was not publicly traded.

(4) Phantom unit awards were made on January 1, 2006 and valued at $14.29 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.

(5) Includes: for Mark A. Fischer $10,142 and $17,339 in matching 401(k) contributions; for Joseph O. Evans $12,667 and $16,257 in matching 401(k) contributions; for Charles A. Fischer $13,631 and $8,229 in matching 401(k) contributions; for Larry E. Gateley $10,822 and $15,866 in matching 401(k) contributions; for Robert W. Kelly II $13,040 in matching 401(k) contributions in 2006 and 2007, respectively.

(6) Includes $10,318 and $14,526 in matching 401(k) contributions and $89,041 and $135,218 in payments for 2006 and 2007, respectively, 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 80% vested at June 30, 2006 and 100% vested at June 30, 2007.

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2007 GRANTS OF PLAN-BASED AWARDS TABLE

There were no awards of phantom units to any NEO during 2007.

2007 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

The following table shows outstanding phantom unit awards as of December 31, 2007 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	NA	NA	NA	NA	NA	3,974	$	65,730	NA	NA
Larry E. Gateley	NA	NA	NA	NA	NA	21,894		362,127	NA	NA
James M. Miller	NA	NA	NA	NA	NA	21,894		362,127	NA	NA
Robert W. Kelly II	NA	NA	NA	NA	NA	21,894		362,127	NA	NA

(1) For Joseph O. Evans, phantom units vest as follows: 3,554 units on July 1, 2010 and 420 units on January 1, 2011; for Larry E. Gateley and James M. Miller, phantom units vest as follows: 19,306 units on January 1, 2009; 1,749 units on January 1, 2010; and 839 units on January 1, 2011; for Robert W. Kelly II, phantom units vest as follows: 19,306 units on January 1, 2009; 1,749 units on January 1, 2010; and 839 units on January 1, 2011.

(2) The table assumes a market value of $16.54 at December 31, 2007 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.

Change of Control Severance Agreements

Each of our NEO’s is party to a change of control severance agreement pursuant to which the officers are entitled to certain severance benefits. Under these agreements, if the officer’s employment is terminated except for cause and not in connection with the officer’s death, disability or retirement within the two year period following a change in control of our company, or if the officer terminates his own employment for good reason during such period, he is entitled to a severance payment. The severance payment will be paid in equal monthly installments over a 24-month period and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to his termination date, plus (B) the officer’s target bonus for the full year in which the termination date occurred or, if no target bonus has been established, then the most recent bonus paid. The multipliers for each of our NEO’s are as follows: Mr. Mark Fischer, 3; Mr. Evans, 2.5; Messrs. Gateley, Miller and Kelly, 2. The officer will also be entitled to certain employee benefits, including life, heath, medical, dental and other insurance, for a period of 12 months following his termination date.

Under the severance agreements, “change in control” is generally defined as (1) the acquisition by any group other than Mark A. Fischer and his affiliates of 50% or more of the voting securities of the company, (2) a merger of the company, or (3) the sale or disposition of all or substantially all of the assets of the company; provided in the case of (2) and (3), no change in control shall be deemed to occur if, immediately following such merger, sale or disposition, the holders of the voting securities of the company prior to such transaction beneficially own more than 50% of the common stock of the company resulting from such transaction in substantially the same proportions as their previous ownership. “Cause,” “retirement,” “disability” and “good reason” have the meanings set forth in the severance agreements.

The table below quantifies amounts that would have been paid pursuant to the change of control severance agreements assuming a qualifying termination following a change in control took place on December 31, 2007.

Name	Base Salary		Target Bonus		Multiplier	Benefits		Total
Mark A. Fischer	$	488,000	$	400,000	3	$	17,339	$	2,681,339
Joseph O. Evans		277,000		192,000	2.5		16,257		1,188,757
Larry E. Gateley		232,000		144,000	2		15,866		767,866
James M. Miller		220,000		137,000	2		14,526		728,526
Robert W. Kelly II		220,000		137,000	2		13,040		727,040

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.

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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 2007 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 5 years) by five 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 2007 Outstanding Equity Awards Table.

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 100% vested at June 30, 2007. Mr. Miller may terminate his employment with us at any time on or after July 1, 2007, without any part of the overriding royalty interest granted reverting to us. In 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.

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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, 2007 were $400,000, $192,000, $144,000, $137,000 and $137,000 for Messrs. Mark A. Fischer, Joseph O. Evans, Larry E. Gately, James M. Miller, and Robert W. Kelly II 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.

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 24, 2008, 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.

	Beneficial ownership
Name(1)	Number	Percent
Mark A. Fischer(2)	372,500	42.5	%
Altoma Energy G.P.(3)	224,500	25.6	%
Charles A. Fischer, Jr.(4)	224,500	25.6	%
CHK Holdings, L.L.C.(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 CHK Holdings, L.L.C.) 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., one of our directors, 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 CHK Holdings L.L.C. is 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, CHK Holdings is an indirect wholly owned subsidiary of Chesapeake Energy Corporation.

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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 $612,075, $622,617 and $610,838 in 2005, 2006 and 2007, respectively. Payments on these interests to Mark A. Fischer were $120,373, $84,837 and $72,845 in 2005, 2006 and 2007, respectively. Payments on these interests to Charles A. Fischer, Jr. were $31,758, $21,919 and $17,987 in 2005, 2006 and 2007, 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, 2007 on these properties. In addition, Chesapeake participates in ownership of properties operated by the Company. During the year ended December 31, 2007, the Company paid revenues and recorded joint interest billings of $1,409,000 and $1,552,000, respectively to Chesapeake. There were no significant amounts receivable or payable to Chesapeake at December 31, 2007.

On December 28, 2005, the Company’s chief executive officer acquired the Company’s beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112,000 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.

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

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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 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.

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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.

Pointe Vista Development, L.L.C.

On December 7, 2007, our board of directors approved the sale of Pointe Vista Development, L.L.C, an indirect, wholly owned subsidiary of the Company, to Fischer Investments, L.L.C., an Oklahoma limited liability company controlled by Mark A. Fischer, our Chairman, Chief Executive Officer and President, for approximately $3.2 million. The sale of this non-core asset was approved by our board of directors in an effort to focus on our core business areas of oil and gas production and exploitation. Our board of directors determined that the terms of the transaction were no less favorable to us than those that could have been obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a person who was not an affiliate of ours. The transaction was also approved by our stockholders who are not affiliates of Mark A. Fischer.

Review, Approval or Ratification of Transactions with Related Persons

Our Board of Directors is responsible for approving all related party transactions between Chaparral and any officer or director that would potentially require disclosure. The Board expects that any transactions in which related persons have a direct or indirect interest will be presented to the Board for review and approval and has adopted a written policy regarding related party transactions. Pursuant to the policy, certain key employees may be allowed to invest in certain wells or projects in which we have an ownership position, provided that Board approval is required if the aggregate investment by employees in a single well or project exceeds 5% of our investment, and no individual shall participate with more than a 2% investment in such project. In determining whether to approve such investment, the Board will consider, among other factors, whether there is an appropriate business reason to allow such investment, that the investment is consistent with our Code of Business Conduct, and that the investment shall allocate risks no less favorable to us than to such employee. Chaparral is not aware of any transaction that was required to be reported in its filings with the SEC where such policies and procedures either did not require review or were not followed. There have been no employee investments in wells as of the date of this filing. This policy has been terminated by unanimous vote of the Board of Directors in March, 2008.

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ITEM 14.    PRINCIPAL ACCOUNTANT 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 2007. 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 2006 and 2007 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 2007(2)	$	414,711	$	4,036	$	21,160
Fiscal 2006(2)	$	512,827	$	255,111	$	39,156

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

(2) There were no fees billed in 2006 or 2007 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 2007 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

Exhibit No.	Description
3.1*	Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (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)
3.2*	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)
3.3*	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*	Third Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, 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 4.5 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 2007)

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Exhibit No.	Description
4.6*	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)
4.7*	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)
4.8*	First Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, to Indenture dated as of January 18, 2007 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.8 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 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)
	[Amended Phantom Stock Plan TBD]
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*	First Amendment to Seventh Restated Credit Agreement, dated as of May 11, 2007, by and among the Company, Chaparral Energy, L.L.C., as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto. (Incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q, filed May 15, 2007)

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Exhibit No.	Description
10.11*	Second Amendment to Seventh Restated Credit Agreement, dated as of July 3, 2007, by and among the Company, Chaparral Energy, L.L.C., as Borrower Representative for the Borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.11 to the Company’s Registration on Form S-l (SEC File No. 333-130749), filed on July 20, 2007)
10.12*	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)
10.13*	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)
10.14*	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)
10.15†	Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof
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

† 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: March 31, 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	Title	Date
/S/    MARK A. FISCHER         Mark A. Fischer	President, Chief Executive Officer and Chairman (Principal Executive Officer)	March 31, 2008
/S/    JOSEPH O. EVANS         Joseph O. Evans	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer) and Director	March 31, 2008
/S/    CHARLES A. FISCHER, JR.         Charles A. Fischer, Jr.	Director	March 31, 2008

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