Chaparral Energy (CHAP) 10-K 2008 FY Annual report

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, 2008

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 Act.    Yes  x    No  ¨

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 (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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 common equity 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 30, 2009.

CHAPARRAL ENERGY, INC.

Index to Form 10-K

Part I
Items 1. and 2. Business and Properties	5
Item 1A. Risk Factors	24
Item 1B. Unresolved Staff Comments	33
Item 2. Properties	33
Item 3. Legal Proceedings	33
Item 4. Submission of Matters to a Vote of Security Holders	34
Part II
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6. Selected Financial Data	36
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	60
Item 8. Financial Statements and Supplementary Data	63
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	98
Item 9A. Controls and Procedures	98
Item 9B. Other Information	99
Part III
Item 10. Directors, Executive Officers and Corporate Governance	100
Item 11. Executive Compensation	102
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	112
Item 13. Certain Relationships and Related Transactions, and Director Independence	112
Item 14. Principal Accounting Fees and Services	115
Part IV
Item 15. Exhibits and Financial Statement Schedules	116
Signatures	119

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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.

BBtu One billion British thermal units.

Bcf One billion cubic feet of natural gas.

Bcfe One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

Btu British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Basin A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

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 (decrease) in future development costs divided by total proved reserve acquisitions, extensions and discoveries, improved recoveries, and revisions.

Henry Hub spot price The price of natural gas, in dollars per MMbtu, being traded at the Henry Hub in Louisiana in transactions for next-day delivery, measured downstream from the wellhead after the natural gas liquids have been removed and a transportation cost has been incurred.

Horizontal drilling A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Infill wells Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

MBbl One thousand barrels of crude oil, condensate, or natural gas liquids.

Mcf One thousand cubic feet of natural gas.

Mcfe One thousand cubic feet of natural gas equivalents.

MMBbl One million barrels of crude oil, condensate, or natural gas liquids.

MMBtu One million British thermal units.

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MMcf One million cubic feet of natural gas.

MMcfe One million cubic feet of natural gas equivalents.

NYMEX The New York Mercantile Exchange.

Net acres The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 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 Securities and Exchange 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 homogeneous 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.

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Seismic survey Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.

Spacing The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

Unit The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

WTI Cushing spot price The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.

Waterflood The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.

Wellbore The hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole.

Working interest The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Zone A layer of rock which has distinct characteristics that differ from nearby layers of rock.

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PART I

Unless the context requires otherwise, references in this annual report to the “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 natural gas industry in the “Glossary of terms” at the beginning of this annual report.

ITEMS 1.    AND 2.    BUSINESS AND PROPERTIES

Chaparral Energy, Inc.

We are 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.

As of December 31, 2008, we had estimated proved reserves of 680.1 Bcfe (74% proved developed and 45% crude oil) with a PV-10 value of approximately $932.7 million. For the year ended December 31, 2008, our average daily production was 115.9 MMcfe with an estimated reserve life of 16 years. For the year ended December 31, 2008, our oil and gas revenues were $501.8 million. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 17.

For the period from 2004 to 2008, our proved reserves and production grew at a compounded annual growth rate of 12% and 22%, 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, 2008, we made capital expenditures of $302.7 million, including $171.0 million for developmental drilling and $45.9 million for acquisitions. The majority of our capital expenditures for developmental drilling in 2008 were 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.

Due to the current reduced prices for oil and natural gas, we plan to keep our 2009 exploration and development expenditures within cash flow. The 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

Business Strengths

Consistent track record of reserve additions and production growth. From 2004 to 2008, we have grown proved reserves and production by a compounded annual growth rate of 12% and 22%, respectively. We have achieved this through a combination of drilling and acquisition success. Our reserve replacement ratio, which reflects our reserve additions from acquisitions, extensions and discoveries, and improved recoveries in a given period stated as a percentage of our production in the same period, has averaged 599% per year since 2002. We replaced approximately 1,165%, 372%, and 200% of our production in 2006, 2007, and 2008, respectively.

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Our average fully developed FD&A cost over the period 2006 through 2008 was $7.21 per Mcfe. Excluding the effects from downward price revisions and reduced future development costs that occurred during 2008, our three-year average fully developed FD&A cost was $3.73 per Mcfe.

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 2006, 2007 and 2008, our capital expenditures for acquisitions of proved properties were $484.4 million, $41.7 million and $39.2 million, respectively. These acquisition capital expenditures represented approximately 73%, 18%, and 13%, respectively, of our total capital expenditures and approximately 94%, 13%, and 17%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries and improved recoveries for those periods. As part of our plan to keep capital expenditures within cash flow, we have not budgeted any significant amounts for acquisitions in 2009.

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. Based on the December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of gas, we had an inventory of over 644 proved developmental drilling locations. Utilizing management’s estimated prices of $60.00 per Bbl of oil and $6.00 per Mcf of gas, we had an inventory of 1,921 additional potential drilling locations, which combined represent over 16 years of drilling opportunities based on our 2009 drilling rate.

	Identified proved undeveloped drilling locations	Identified additional potential drilling locations	Developed Acreage Net	Undeveloped Acreage Net
Mid-Continent	489	1,026	383,168	66,041
Permian Basin	34	396	54,447	19,171
Gulf Coast	7	43	43,231	14,340
Ark-La-Tex	7	17	14,772	—
North Texas	15	364	19,733	6,731
Rocky Mountains	92	75	14,691	2,611
Total	644	1,921	530,042	108,894

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. As more fully discussed in the section “Risk Factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. We have experienced a high historical drilling success rate of approximately 98% on a weighted average basis during 2006, 2007 and 2008. For the year ended December 31, 2008, we spent $176.1 million of developmental drilling and exploration costs to drill 80 (73 net) operated wells and to participate in 246 (6 net) wells operated by others, representing 78% of our additions to reserves. For 2009, we have budgeted $38.0 million to drill more than 40 operated wells and to participate in more than 100 wells operated by others.

Enhanced oil recovery expertise and asset. 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

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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, 2008, our proved reserves included six 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 a 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 initiated polymer injection in this unit in a pilot program in December 2007. In the pilot area, we believe we are seeing production response as production has increased from 90 Bbls of oil per day to 130 Bbls of oil per day. We plan to expand this polymer EOR program and ultimately introduce CO₂ injection into this unit.

Experienced management team. Mark A. Fischer, our Chief Executive Officer 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 29 years of experience in the oil and gas industry. Individuals in our 23-person management team have an average of over 29 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, 2008, we spent approximately $171.0 million on development drilling, which represents 56% 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 $38.0 million, or approximately 75% of our capital expenditures, on developmental drilling in 2009.

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 2006, we also made a larger acquisition that complemented our existing properties in our core areas. During the year ended December 31, 2008, we made approximately $39.2 million of proved reserve acquisitions, or 13% of our total capital expenditures. As part of our plan to keep capital expenditures within cash flow, we have not budgeted any significant amounts for acquisitions in 2009.

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 our Company 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, 2008, we had an inventory of 806 enhancement projects requiring total estimated capital expenditures of $69.4 million.

Expand CO₂ EOR activities. As of December 31, 2008, we have accumulated interests in 61 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO₂ EOR operations and we are expanding

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our CO₂pipeline system to initiate CO₂ injection in certain of these properties. We began CO₂ injection in our Perryton Unit in December 2006 and will begin CO₂ injection in our Booker Area Units in the second quarter of 2009 and in our NW Camrick Unit in 2010. To support our existing CO₂ EOR projects, we currently inject approximately 33.4 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 between Liberal, Kansas and Booker, Texas. We have installed compression facilities to capture approximately 16 MMcf per day of CO₂ from the Arkalon ethanol plant and expect to initiate injection of this CO₂ into the Booker area fields in the second quarter of 2009.

Pursue modest exploration program. In the current low-priced commodity environment, we do not plan to spend any significant amount on exploratory 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, 2008, we operated properties comprising approximately 82% of our proved reserves.

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations, for capital investments, and to lock in returns on acquisitions, we enter into commodity price swaps, costless collars, and basis protection swaps. We consider all these derivative instruments to be economic hedges of our proved developed production, regardless of whether hedge accounting is applied. As of December 31, 2008, we had commodity price swaps, costless collars, and basis protection swaps in place for approximately 50% of our most recent internally estimated proved developed gas production for 2009 through 2011. We also had commodity price swaps and costless collars in place for approximately 66% of our most recent internally estimated proved developed oil production for 2009 through 2013. While our derivative activities protect our cash flows during periods of commodity price declines, we recorded losses on derivative activities of $8.8 million and $51.9 million for the years ended December 31, 2006 and 2007, respectively, through a period of increasing commodity prices. For the year ended December 31, 2008, we recorded a gain on derivative activities of $50.5 million. In December 2008, we received proceeds of $32.6 million from the monetization of derivative contracts which had original settlement dates from January through June 2009.

Properties

The following table presents our proved reserves and PV-10 value as of December 31, 2008 and average daily production for the year ended December 31, 2008 by our areas of operation.

	Proved reserves as of December 31, 2008							Average daily production (MMcfe per day) Year ended December 31, 2008
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	Percent of total MMcfe		PV-10 value ($mm)
Mid-Continent	40,449	244,062	486,756	71.5	%	$	636.7	77.6
Permian Basin	5,740	66,829	101,269	14.9	%		163.8	18.8
Gulf Coast	1,551	34,593	43,899	6.5	%		78.7	9.2
Ark-La-Tex	712	15,828	20,100	3.0	%		18.4	4.8
North Texas	1,692	4,839	14,991	2.2	%		21.9	3.0
Rocky Mountains	1,139	6,215	13,049	1.9	%		13.2	2.5
Total	51,283	372,366	680,064	100	%	$	932.7	115.9

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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, 83% of our 2008 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, 2008, we owned interests in 8,324 gross (2,741 net) producing wells and we operated wells representing approximately 82% 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, 2008, accounted for 72% of our proved reserves and 68% of our PV-10 value. We own a working interest in 5,393 producing wells in the Mid-Continent Area, of which we operate 2,024. The Mid-Continent Area has fifteen of our top twenty largest properties in terms of PV-10 value. During the year ended December 31, 2008, our net average daily production in the Mid-Continent Area was approximately 77.6 MMcfe per day, or 67% 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, is 23,080 acres in size and has cumulative production of approximately 317 MMBbl of oil (primary and secondary). The North Burbank Unit accounted for 47,113 MMcfe of our proved reserves, $27.9 million of our PV-10 value as of December 31, 2008 and 3,316 (2,726 net) MMcfe of our year ended December 31, 2008 production. The producing zones are the Red Fork and Bartlesville and occur at a depth of 3,000 feet. We own 99.25% of the field and are also the operator. As of December 31, 2008, the field was producing 1,510 (1,242 net) Bbls of oil per day from 277 producing wells. There are also 187 active injection wells and 483 temporarily abandoned wells at December 31, 2008. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in reinstituting 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 of oil per day to 1,200 Bbls of oil 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 reinstituted a polymer flood on 485 acres adjacent to Block A on a 19-well pattern in December 2007. Production has increased in this pilot area from 90 Bbls of oil per day to 130 Bbls of oil per day as of December 31, 2008. Since taking over the field on November 1, 2006, we have returned 70 temporarily abandoned wells to production with initial rates of production ranging between 6 and 25 Bbls of oil per day. We believe that this field also may have upside with the injection of CO₂.

South Burbank Unit—Osage County, Oklahoma. The South Burbank Unit is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit and covers 4,386 acres. It was discovered in 1934 and unitized in 1935. The South Burbank Unit has produced 56.7 MMBbls of oil from the Burbank Sand from both primary and waterflood recovery efforts. The Burbank Sand occurs at a depth of 2,850 feet. Recently, we have been drilling infill and stepout locations in the unit area for both the deeper Mississippi Chat, which occurs some 50 feet below the shallower Burbank Sand, and to the shallower Burbank Sand. It is currently estimated that the Mississippi Chat may be productive under a significant portion of the southern half of the South Burbank Unit. Four wells have been drilled and completed in the Mississippi Chat and are proving successful with initial potentials as high as 87 Bbls of oil per day. Three wells have been drilled and completed in the shallower Burbank Sand and are also proving successful with initial potentials ranging between 17 and 30 Bbls of oil per day. We drilled five of these wells in this area in 2008. We currently have a Company-owned drilling rig working full time in this area and expect to drill ten wells in 2009. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts.

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Camrick area—Beaver and Texas Counties, Oklahoma and Ochiltree County, Texas. The Camrick area represented approximately 4% of our proved reserves and 3% of our PV-10 value (29,433 MMcfe and $30.2 million, respectively) at December 31, 2008. 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 MMBbls of primary reserves and approximately 13.1 MMBbls of secondary reserves. There were 47 active producing wells in this area that produced 3,019 (1,475 net) MMcfe during the year ended December 31, 2008. Currently, CO₂ injection operations are continuing in the Phase I, II and III areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Area from approximately 115 Bbls of oil (690 Mcfe) per day in 2001 from 11 wells to approximately 1,435 (775 net) Bbls of oil (8,610 Mcfe) per day as of December 31, 2008 from 47 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 represented 6% of our proved reserves and 8% of our PV-10 value (38,472 MMcfe and $77.9 million, respectively) at December 31, 2008. 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 40.3 MMBbls of oil and 260.2 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1966, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have 34 active producing wells in this unit as of December 31, 2008. We are scheduled to drill five wells in 2009.

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Play accounted for 20,508 MMcfe of our proved reserves and $41.9 million of our PV-10 value as of December 31, 2008. 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. As of December 31, 2008, we own interests in 31 Cleveland Sand producing wells. We drilled five wells in 2007 and four wells in 2008. We employed horizontal drilling technology in most of our drilled wells in this area. We expect that future wells will also utilize horizontal technology.

Granite Wash Horizontal Play—Washita County, Oklahoma. The objective target of this play is the Des Moinesian Granite Wash “A”, “B” and “C” zones at an average depth of approximately 12,500 feet. To date, this play has encompassed an area approximately three townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells utilize a lateral drilled up to 4,000 feet horizontally in the Granite Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We recently drilled a new well, the Roxanne 1-17H, in which we have a 25% working interest, which came on line at rates of 3,906 (793 net) Mcf of natural gas per day and 365 (74 net) Bbls of oil per day. We participated in six wells in this play in 2008 and we expect to drill and/or participate in the drilling of an additional three Granite Wash horizontal wells in 2009.

Anadarko Basin Woodford Shale Play-Western Oklahoma. As of December 31, 2008, we have a significant acreage position in the emerging Woodford Shale Resource Play of western Oklahoma. We own and control approximately 380,000 gross acres and 77,700 net acres, which primarily are held by production from other formations. The Woodford Shale beneath our acreage ranges in thickness from approximately 80 to 280 feet thick at depths from 11,500 feet to 16,000 feet. The horizontal development of this non-conventional resource

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play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Grady and Caddo with over 30 Woodford targeted wells drilled to date. Gas in place is estimated to be between 145 to 200 Bcf per section with initial development well density to be four wells per section. The average recovery is expected to be five to eight Bcf per well at an average cost of seven to nine million dollars. Operators in the play have reported initial daily production rates in the range of five to eight MMcf of gas per day per well.

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit, which covers approximately 1,300 acres, was discovered in 1949 and 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 12,397 MMcfe of our proved reserves and $8.9 million of our PV-10 value as of December 31, 2008. 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. As of December 31, 2008, we had 47 active producing wells in this unit.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit, which is 2,335 acres, was discovered in 1915 and unitized in 1977. This unit had proved reserves of 1,684 MMcfe and a PV-10 value of $1.2 million at December 31, 2008. We operate this unit with a working interest of 82%. 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, as of December 31, 2008, the unit has 64 producing wells and 46 active injection wells. The unit is currently producing 370 (247 net) Bbls of oil per day.

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 8,764 MMcfe of our proved reserves and $7.6 million of our PV-10 value at December 31, 2008. There are currently 26 producing wells and 13 active injection wells, with current production of approximately 236 (137 net) Bbls of oil per day. We operate the field with a working interest of 64%. 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 of oil. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls of oil per day in 1964 in the adjacent East Sivells Bend Unit and one well in our unit tested 104 Bbls of oil per day for a short time. 3-D 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.

CO₂ EOR—Various counties, Oklahoma, Kansas, New Mexico and Texas. We plan to initiate CO₂ injection in three Booker units in 2009 and in our NW Camrick Unit in 2010. On December 31, 2008, we had in place transportation and supply agreements to provide the necessary CO₂ for these projects. We have accumulated 61 properties in Oklahoma, Kansas, New Mexico and Texas that meet the criteria for CO₂ EOR operations. We have a 100% ownership in 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 own a 100% interest in approximately 126 miles of pipeline located between Liberal, Kansas and Booker, Texas. We have installed compression facilities to capture approximately 16 MMcf per day of CO₂ from the Arkalon ethanol plant and expect to initiate injection of this CO₂ into the Booker area fields in the second quarter of 2009. 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.

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Permian Basin

The Permian Basin Area is the second of our two core areas and, as of December 31, 2008, accounted for 15% of our proved reserves and 18% of our PV-10 value. We own an interest in 1,604 wells in the Permian Basin, of which we operate 337. Three of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2008, our net average daily production in the Permian Basin Area was approximately 18.8 MMcfe per day, or 16% of our total net average daily production. Similar to the Mid-Continent Area, the Permian Basin Area is characterized by 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 13,787 MMcfe of our proved reserves and $28.4 million of our PV-10 value at December 31, 2008. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 5,200 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 2007, we drilled eight wells in this play. We drilled 16 wells in 2008 and plan to drill two wells in 2009.

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 11 producing wells in this play. The Haley Area represents 28,329 MMcfe of our proved reserves and $43.7 million of our PV-10 value at December 31, 2008. Production has been established from four main intervals: (1) the Bone Springs at a depth of approximately 10,100 to 11,000 feet; (2) the Strawn at a depth of approximately 15,500 feet; (3) the Atoka at a depth of approximately 16,000 feet; and (4) 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, four 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. We recently drilled the Bowdle 47 No. 2 to test the Morrow and Atoka intervals. This well began selling gas in late November 2008, and is currently producing at approximately 15.5 MMcfe per day gross and 11.2 MMcfe net to our interests. We are currently pipeline limited and pipeline construction is underway that should allow the Bowdle 47 No. 2 to produce at even higher rates. We expect to drill an offset to the Bowdle 47 No. 2 well in the fourth quarter of 2009. We also drilled the F.D. Russell #2 well which encountered several Atoka sands and came on-line in April 2008. This well is currently producing at approximately two MMcf per day.

Gulf Coast

The Gulf Coast Area is the most active of our four growth areas and, as of December 31, 2008, accounted for 6% of our proved reserves and 9% of our PV-10 value. We own an interest in 185 wells in the Gulf Coast Area, of which we operate 121. 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 complements our long-life reserves and adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Nueces County, TX. We own interests in approximately 3,405 net producing acres and 10,020 net non-producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate six active producing wells in this area. As of December 31, 2008, the wells in Nueces County, Texas account for 1,303 MMcfe of our proved reserves and $2.6 million of our PV-10 value. We are currently processing a 51-square mile proprietary 3-D 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.

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Ark-La-Tex

As of December 31, 2008, the Ark-La-Tex Area accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 104 wells in the Ark-La-Tex Area, of which we operate 52. These reserves are characterized by shorter life and higher initial potential. Most of our activity is centered in the Jewitt Field where we are participating with another party and drilled 16 wells in 2008.

North Texas

As of December 31, 2008, the North Texas Area accounted for 2% of our proved reserves and 2% of our PV-10 value. We own an interest in 865 wells in the North Texas Area, of which we operate 108.

Rocky Mountains

As of December 31, 2008, the Rocky Mountains Area accounted for 2% of our proved reserves and 1% of our PV-10 value. We own an interest in 173 wells in the Rocky Mountains Area, of which we operate 39.

Oil and Natural Gas Reserves

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2008. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (68% of PV-10 value) and by Ryder Scott Company, L.P. (7% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (25% of PV-10 value).

	Net proved reserves
	Oil (MBbl)	Natural gas (MMcf)	Total (MMcfe)	PV-10 value (In thousands)
Developed—producing	31,145	214,016	400,886	$	641,194
Developed—non-producing	9,237	49,315	104,737		143,398
Undeveloped	10,901	109,035	174,441		148,100
Total proved	51,283	372,366	680,064	$	932,692

The estimated reserve life as of December 31, 2006, 2007 and 2008 was 28.0, 24.3 and 16.0 years, respectively. The estimated reserve life was calculated by dividing total proved reserves by production volumes for the year indicated. The shorter reserve life of 16 years in 2008 was primarily a result of reduced proven reserves associated with the lower end of year SEC pricing.

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

(Dollars in thousands, except prices)	2006		2007		2008
Future net revenue	$	3,518,020	$	6,203,720	$	1,918,270
PV-10 value		1,494,063		2,671,982		932,692
Standardized measure of discounted future net cash flows		1,082,209		1,793,980		755,013
Oil price (per Bbl)	$	61.06	$	96.01	$	44.60
Natural gas price (per Mcf)	$	5.64	$	6.80	$	5.62

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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, 2008 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 a working interest, and net wells is the sum of our working interest in all wells.

	Total wells
	Gross	Net
Crude oil	6,188	2,071
Natural gas	2,136	670
Total	8,324	2,741

The following table details our gross and net interest in producing wells in which we have a working interest and the number of wells we operated at December 31, 2008 by area.

	Total wells		Operated Wells
	Gross	Net
Mid-Continent	5,393	2,043	2,024
Permian Basin	1,604	373	337
Gulf Coast	185	113	121
Ark-La-Tex	104	47	52
North Texas	865	126	108
Rocky Mountains	173	39	39
Total	8,324	2,741	2,681

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2008 by area.

	Developed		Undeveloped
	Gross	Net	Gross	Net
Mid-Continent	898,743	383,168	77,704	66,041
Permian Basin	78,188	54,447	20,467	19,171
Gulf Coast	71,959	43,231	22,402	14,340
Ark-La-Tex	26,920	14,772	—	—
North Texas	25,525	19,733	7,827	6,731
Rocky Mountains	43,518	14,691	3,252	2,611
Total	1,144,853	530,042	131,652	108,894

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

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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.

	2006				2007				2008
	Gross		Net		Gross		Net		Gross		Net
Development wells
Productive	189.0		56.1		214.0		51.7		319		74.9
Dry	1.0		0.2		3.0		1.2		4.0		2.0
Exploratory wells
Productive	1.0		1.0		6.0		5.9		3.0		2.2
Dry	1.0		0.1		0.0		0.0		0.0		0.0
Total wells
Productive	190.0		57.1		220.0		57.6		322.0		77.1
Dry	2.0		0.3		3.0		1.2		4.0		2.0
Total	192.0		57.4		223.0		58.8		326.0		79.1
Percent productive	99	%	99	%	99	%	98	%	99	%	97	%

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, 2006, 2007 and 2008), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2006 and 2007 were prepared by Cawley, Gillespie & Associates, Inc. (36% of PV-10 value in 2007), and Lee Keeling & Associates, Inc. (52% of PV-10 value in 2007). Estimates of our net proved oil and natural gas reserves as of December 31, 2008 were prepared by Cawley, Gillespie & Associates, Inc. (68% of PV-10 value), and Ryder Scott Company, L.P. (7% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (12% and 25% of PV-10 value in 2007 and 2008, respectively).

	As of December 31,
Proved Reserves	2006			2007			2008
Oil (Mbbl)		88,378			99,104			51,283
Natural gas (MMcf)		375,311			392,269			372,366
Natural gas equivalent (MMcfe)		905,579			986,893			680,064
Proved developed reserve percentage		69	%		65	%		74	%
PV-10 value (in thousands)	$	1,494,063		$	2,671,982		$	932,692
Estimated reserve life (in years)(1)		28.0			24.3			16.0
Cost incurred (in thousands):
Property acquisition costs
Proved properties(2)	$	484,404		$	41,724		$	39,201
Unproved properties		4,731			8,032			6,677
Total acquisition costs		489,135			49,756			45,878
Development costs(3)		170,987			165,177			251,690
Exploration costs		7,015			15,287			5,108
Total	$	667,137		$	230,220		$	302,676
Annual reserve replacement ratio(4)		1,165	%		372	%		200	%
Three-year average fully developed FD&A cost ($/Mcfe)(5)	$	2.37		$	3.00		$	7.21

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

(2) Includes $464.9 million of costs related to the acquisition of Calumet Oil Company (“Calumet”) in 2006, and $15.6 million of amounts disbursed from escrow related to title defects and other purchase price allocation adjustments on the Calumet Acquisition in 2007.

(3) Includes $16.1 million of costs related to the construction of a compressor station and CO₂ pipeline in 2008.

(4) Calculated by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note 17 of the notes to our consolidated financial statements. In calculating reserves replacement, we do not use unproved reserve

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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,
	2006				2007				2008
	Reserves replaced		Percent of total		Reserves replaced		Percent of total		Reserves replaced		Percent of total
Purchases of minerals in place	1,093	%	93.8	%	46	%	12.5	%	35	%	17.2	%
Extensions and discoveries	52	%	4.4	%	214	%	57.4	%	155	%	77.6	%
Improved recoveries	20	%	1.8	%	112	%	30.1	%	10	%	5.2	%
Total	1,165	%	100.0	%	372	%	100.0	%	200	%	100	%

(5) Calculated as costs incurred, plus the change in future development costs, divided by total reserve additions as shown below (in Mcfe unless otherwise noted):

	2006			2007			2008(6)
Purchases of minerals in place		354,004			18,850			14,569
Extensions and discoveries		16,736			86,788			65,813
Revisions		(56,423	)		(28,684	)		(348,118	)
Improved recoveries		6,653			45,423			4,380
Total reserve additions		320,970			122,377			(263,356	)
Costs incurred	$	667,137		$	230,220		$	302,676
Changes in future development costs		236,700			337,438			(476,201	)
Total	$	903,837		$	567,658		$	(173,525	)
Three-year average fully developed FD&A cost ($/Mcfe)	$	2.37		$	3.00		$	7.21

(6) Excluding the reduction in reserve quantities resulting from downward price revisions and the reduction in future development costs that occurred during the year, our three-year average fully developed FD&A cost was $3.73 per Mcfe.

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,
	2006		2007		2008
Production:
Oil (MBbls)		1,906		3,356		3,773
Gas (MMcf)		20,949		20,504		19,795
Combined (MMcfe)		32,385		40,640		42,433
Average daily production:
Oil (Bbls)		5,222		9,195		10,309
Gas (Mcf)		57,395		56,175		54,085
Combined (Mcfe)		88,727		111,345		115,939
Average prices (before effect of hedges):
Oil (per Bbl)	$	61.65	$	69.85	$	92.47
Gas (per Mcf)		6.29		6.41		7.72
Combined (per Mcfe)	$	7.69	$	9.00	$	11.82
Average costs per Mcfe:
Lease operating	$	2.21	$	2.57	$	2.84
Production taxes	$	0.58	$	0.65	$	0.80
Depreciation, depletion, and amortization	$	1.61	$	2.10	$	2.37
General and administrative	$	0.45	$	0.54	$	0.53

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Non-GAAP Financial Measures and Reconciliations

The PV-10 value is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using generally accepted accounting principles (“GAAP”). PV-10 value is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 value is equal to the standardized measure of discounted future net cash flows at December 31, 2008 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 value 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 future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value 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 value as of December 31, 2008 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	$	636.7	$	111.5	$	525.2
Permian Basin		163.8		37.9		125.9
Gulf Coast		78.7		19.7		59.0
Ark-La-Tex		18.4		2.3		16.1
North Texas		21.9		4.8		17.1
Rocky Mountains		13.2		1.5		11.7
Total	$	932.7	$	177.7	$	755.0

We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) non-cash deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges.

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Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA mirrors the Consolidated EBITDAX ratio that is used in the covenant calculation required under our Credit Agreement described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under generally accepted accounting principles and, accordingly, it may not be a comparable measurement to those used by other companies. The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the specified periods:

	Year Ended December 31,
	2006			2007			2008
Net income (loss)	$	23,806		$	(4,793	)	$	(54,750	)
Interest expense		45,246			87,656			86,038
Income tax expense (benefit)		14,817			(2,745	)		(34,386	)
Depreciation, depletion, and amortization		52,299			85,842			101,973
Unrealized (gain) loss on ineffective portion of hedges		(18,761	)		8,343			(12,549	)
Non-cash change in fair value of non-hedge derivative instruments		4,592			23,031			(89,554	)
Interest income		(555	)		(755	)		(409	)
Non-cash deferred compensation expense (gain)		82			831			(306	)
Gain on disposed assets		(132	)		(712	)		(177	)
Loss on impairment of oil and gas properties		—			—			281,393
Loss on impairment of ethanol plant		—			—			2,900
Adjusted EBITDA	$	121,394		$	196,698		$	280,173

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;

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

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

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

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

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

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

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before 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;

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

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

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

We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 2007 and 2008, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2009 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 (“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 (“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 (“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

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

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

Water Discharges

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

Air Emissions

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In 2007, the U.S. Supreme Court issued a decision that EPA has authority to regulate greenhouse gas emissions pursuant to the Clean Air Act. Massachusetts v. EPA, 549 U.S. 497 (2007). Additionally, the 2007 Omnibus Spending bill mandated that EPA promulgate regulations requiring mandatory monitoring and reporting of greenhouse gas emissions by June 2009 pursuant to authority provided by the Clean Air Act. EPA proposed its mandatory greenhouse gas monitoring and reporting rule in 2009. These regulations, if promulgated, will require mandatory monitoring and reporting of greenhouse gas emissions from natural gas processing and transmission compression facilities, including fugitive methane emissions and carbon dioxide emissions from flares used to control fugitive methane emissions, exceeding regulatory emission threshold criteria. 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

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costs in order to comply with new monitoring and reporting requirements and/or 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 current requirements of the Clean Air Act.

Other Laws and Regulation

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

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

Natural Gas Sales Transportation

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

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

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

Natural Gas Pipeline Safety

The Department of Transportation, specifically the Pipeline and Hazardous Materials Safety Administration, regulates transportation of natural and other gas by pipeline and imposes minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq. and the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq. We believe that we are currently in substantial compliance with the requirements of these various regulatory requirements mandating federal minimum safety criteria for transporting natural and other gas and hazardous materials via pipeline.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been

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affirmatively applied by state agencies, natural gas gathering is addressed in EPA’s proposed greenhouse gas monitoring and reporting rule and may receive greater regulatory scrutiny in the future.

State Regulation

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

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

Seasonality

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

Title to properties

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

Employees

As of December 31, 2008, we had 859 full-time employees, including 14 geologists and geophysicists, 29 reservoir, production, and drilling engineers and 15 land professionals. Of these, 307 work in our Oklahoma City office and 552 work 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.

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Worldwide demand for oil and natural gas appears to be declining, which could materially reduce our profitability and cash flow.

Based on a number of economic indicators, it appears that growth in global economic activity has slowed substantially. At the present time, the rate at which the global economy will slow has become increasingly uncertain. A slowing of global economic growth will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower oil and natural gas prices, which will reduce our cash flow from operations.

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

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

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

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

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

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

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

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• financial and commercial market uncertainty;

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

• worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Oil and natural gas prices have declined significantly over the past year and may continue to decline. Our profitability is directly related to the prices we receive for the sale of the oil and natural gas we produce. In early July 2008, commodity prices reached levels in excess of $140.00 per Bbl for crude oil and $13.00 per Mcf for natural gas. Market prices currently are in the range of$50.00 per Bbl for crude oil and$4.00 per Mcf for natural gas, a decline of approximately 64% and 69%, respectively, from earlier highs. As a result, our revenue from oil and gas sales is expected to decline significantly in 2009 as compared with 2008. 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.

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Price declines at the end of 2008 resulted in a write down of the carrying values of our properties, and further price declines could result in additional write downs in the future, 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 units-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.

During the fourth quarter of 2008, we recorded a non-cash ceiling test impairment of oil and natural gas properties of $281.4 million as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas.

Prices have remained volatile subsequent to December 31, 2008. This and other factors, without other mitigating circumstances, could cause a future further write down 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 Securities and Exchange 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, 2008 future cash flows used realized prices based on a Henry Hub spot price of $5.62 per Mcf for natural gas and a WTI Cushing spot price of $44.60 per Bbl for oil.

A significant portion of total proved reserves as of December 31, 2008 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2008, approximately 26% 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

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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, 2008, 6% 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 CO₂or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or in the production levels we anticipate. Our ability to develop future reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have a material adverse effect 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, 2008, our total debt was $1,271.6 million. Our maximum commitment amount and the borrowing base under our Seventh Restated Credit Agreement (the “Credit Agreement”) was redetermined to be $600.0 million as of December 24, 2008. Covenants set forth in the indentures for our 8 ¹/2% Senior Notes and the 8 ⁷/8% Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

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 may 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, 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 Credit Agreement is subject to a borrowing base, which was redetermined to be $600.0 million as of December 24, 2008, 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 condition.

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 26% of our total estimated proved reserves (by volume) at December 31, 2008 were

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undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2008 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 17.0%, 11.4% and 10.8% 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.

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

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

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• reporting or other limitations on emissions of greenhouse gases;

• unitization and pooling of properties;

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

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• 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;

• other environmental damages; and

• reporting or other issues arising from greenhouse gas emissions.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, future regulations promulgated pursuant to the Clean Air Act or other mandatory federal legislation may require monitoring and reporting of greenhouse gas emissions and eventually, may impose restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. 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 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, 2008, we had entered into swaps for 25,590 MMcf of our natural gas production for 2009 through 2011 at average monthly prices ranging from $6.97 to $8.03 per Mcf of natural gas. We also entered into collars for 6,540 MMcf of our natural gas production for 2009 through 2010 at $10.00 per Mcf. As of December 31, 2008, we had entered into swaps for 7,196 MBbl of our crude oil production for 2009 through 2013 at average monthly prices ranging from $63.17 to $124.66 per Bbl of oil. We also entered into collars for 1,666 MBbl of our crude oil production for 2009 through 2013 ranging from $100.00 to $110.00 per Bbl of oil. As of December 31, 2008, we had basis protection swaps for 29,790 MMcf of our natural gas production for 2009 through the first quarter of 2011 at average monthly prices ranging from $0.88 to $1.02 per Mcf. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2008 was an asset of approximately $205.7 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 contractual obligations; or

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

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies and is designated as a cash flow hedge,

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the effective portion of changes in the fair value of the derivative is 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, is immediately recognized in loss from oil and gas hedging activities in the statement of operations.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.

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 Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. These persons include the executive officers listed in Item 10 under “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.

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If Mark A. Fischer ceases to be our Chairman, Chief Executive Officer, or President in connection with a change of control, such event could also result in a change of control event occurring under our Credit Agreement, the indenture governing our outstanding Senior Notes or our Phantom 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.

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;

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• 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, 2008 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 $600.0 million, equal to our borrowing base at December 31, 2008, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 million.

The soundness of financial institutions could place our cash deposits at risk.

Current market conditions also elevate the concern over our cash accounts. Our cash investments and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail.

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 Items 1. and 2. Business and Properties—Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Liquidity and Capital Resources—Contractual Obligations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 14, “Commitments and Contingencies,” to the Consolidated Financial Statements. 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 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 receivable was calculated in accordance with the securities purchase agreement and intend to diligently

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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, and amended our petition on December 1, 2008 to clarify that we are also seeking recovery of the purchase price adjustment amount under a breach of contract theory. The sellers responded by filing a counterclaim seeking approximately $4.4 million related to an election under the federal tax code. Discovery in the lawsuit is proceeding, and mediation is scheduled in the second quarter of 2009. As of December 31, 2007 and 2008, the recorded receivable was approximately $14.4 million and was recorded in other assets on the consolidated balance sheet. As of December 31, 2007 and 2008, the recorded payable related to the election under the federal tax code was $4.4 million and was included in accounts payable and accrued liabilities 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

On October 16, 2008, our stockholders adopted certain resolutions by written consent related to our expected merger with Edge Petroleum Corporation. The resolutions approved the adoption of certain of Edge’s equity incentive plans and the adoption of a long-term incentive plan for the Company. These resolutions were contingent upon the closing of the merger. Because the merger was terminated and never closed, these resolutions never became effective.

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PART II

ITEM 5. MARKET 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 30, 2009, we had 877,000 shares of common stock outstanding held by three record holders.

We have not paid any dividends on our common stock in either of the last two years and 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. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for more information regarding the restrictions on our ability to pay dividends.

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ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data 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, 2008 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 per share amounts)	2004			2005			2006			2007			2008
Operating results data:
Revenues
Oil and gas sales	$	113,546		$	201,410		$	249,180		$	365,958		$	501,761
Loss from oil and gas hedging activities		(21,350	)		(68,324	)		(4,166	)		(28,140	)		(76,417	)
Service company sales		—			—			—			20,611			34,272
Total revenues		92,196			133,086			245,014			358,429			459,616
Costs and expenses
Lease operating		26,928			42,147			71,663			104,469			120,487
Production taxes		8,272			14,626			18,710			26,216			33,815
Depreciation, depletion and amortization		17,533			31,423			52,299			85,431			100,528
Loss on impairment of oil & gas properties		—			—			—			—			281,393
Loss on impairment of ethanol plant		—			—			—			—			2,900
General and administrative		5,985			9,808			14,659			21,838			22,370
Service company expenses		—			—			—			18,852			31,656
Total costs and expenses		58,718			98,004			157,331			256,806			593,149
Operating income (loss)		33,478			35,082			87,683			101,623			(133,533	)
Non-operating income (expense)
Interest expense		(6,162	)		(15,588	)		(45,246	)		(87,656	)		(86,038	)
Non-hedge derivative gains (losses)		—			—			(4,677	)		(23,781	)		126,941
Termination fee		—			—			—			—			3,500
Merger costs		—			—			—			—			(1,400	)
Other income		279			665			792			2,276			1,394
Net non-operating income (expense)		(5,883	)		(14,923	)		(49,131	)		(109,161	)		44,397
Income (loss) before income taxes and minority interest		27,595			20,159			38,552			(7,538	)		(89,136	)
Income tax expense (benefit)		9,880			7,309			14,817			(2,745	)		(34,386	)
Minority interest		—			—			(71	)		—			—
Net income (loss)	$	17,715		$	12,850		$	23,806		$	(4,793	)	$	(54,750	)
Net income (loss) per share (basic and diluted)	$	22.86		$	16.58		$	29.74		$	(5.47	)	$	(62.43	)
Weighted average number of shares used in calculation of basic and diluted earnings per share		775,000			775,000			800,500			877,000			877,000
Cash flow data:
Net cash provided by operating activities	$	46,870		$	55,744		$	89,154		$	113,443		$	146,914
Net cash used in investing activities		(92,141	)		(325,068	)		(703,804	)		(239,442	)		(263,988	)
Net cash provided by financing activities		54,061			257,080			621,855			128,883			157,499
	As of December 31,
(Dollars in thousands expect per share amounts)	2004			2005			2006			2007			2008
Financial position data:
Cash and cash equivalents	$	13,842		$	1,598		$	8,803		$	11,687		$	52,112
Total assets		308,827			647,379			1,331,435			1,530,898			1,712,836
Total debt		176,622			446,544			976,272			1,114,237			1,271,589
Retained earnings		48,692			58,126			80,883			76,090			21,340
Accumulated other comprehensive income (loss), net of income taxes		(12,107	)		(47,967	)		(3,946	)		(73,839	)		82,133
Total equity		36,586			10,167			177,864			103,178			204,400
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, 2008, we had estimated proved reserves of 680.1 Bcfe, with a PV-10 value of $932.7 million. Our reserves were 74% proved developed reserves and 45% crude oil. Our estimated proved reserves have decreased significantly since December 31, 2007 due to a decrease in price from $96.01 per Bbl and $6.80 per Mcf in 2007 to $44.60 per Bbl and $5.62 per Mcf, in 2008. As of December 31, 2007, we had estimated proved reserves of 986.9 Bcfe with a PV-10 value of $2.7 billion, of which 65% were proved developed reserves 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.

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 17.0%, 11.4% and 10.8% 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.

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.

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

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

• the quantity of our proved oil and gas reserves;

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

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

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

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. Due to the recent turmoil in the market and the sharp decline in oil and natural gas prices during the fourth quarter of 2008, we plan to keep our capital expenditures within our cash flow for 2009.

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

• Current Market Conditions. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit market crisis includes our revolving credit facility, counterparty risks related to our trade credit and derivative instruments, and risks related to our cash investments.

Our cash accounts and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail. As of December 31, 2008, cash with a recorded balance totaling $49.1 million was held at JP Morgan Chase Bank, N.A.

We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers. Some of these parties may experience liquidity problems. Nonperformance by a trade creditor could result in losses. We also have significant net derivative assets that are held by affiliates of our lenders. As of December 31, 2008, approximately 88% of our net derivative asset of $205.7 million was held by JP Morgan Chase Bank, N.A., Calyon Credit Agricole CIB, and The Royal Bank of Scotland plc.

Our oil and gas sales revenues are derived from the sale of oil, natural gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and the demand for, oil and natural gas. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and natural gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil producing countries, and governmental regulation, legislation and policies.

Oil and natural gas prices declined significantly during the fourth quarter of 2008, which will reduce our cash flows from operations in future periods in which prices remain at or below the current levels. The commodity price swaps and costless collars that cover approximately 66% of our expected PDP oil production through December 2013 and approximately 50% of our expected PDP natural gas production through December 2011 will, however, become more valuable if prices continue to decline.

• Credit Facility. Our current credit facility is a revolving credit facility in the amount of $600.0 million. At December 31, 2008, we had $594.0 million outstanding under the revolving credit facility and $2.7 million was utilized by outstanding letters of credit. The borrowing base is subject to redetermination on May 1, 2009. If the outstanding borrowings under the Credit Agreement were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess.

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The revolving credit facility is scheduled to mature on October 31, 2010. Should current credit market volatility be prolonged, future extensions of our credit facility may contain terms that are less favorable than those of our current credit facility. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability, and we may not meet the required Current Ratio, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

Covenants set forth in the indentures for our 8 ¹/2% Senior Notes and the 8 ⁷/8% Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

• Impairment of oil and gas properties.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 our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the fourth quarter of 2008, we recorded a ceiling test impairment of oil and gas properties of $281.4 million as a result of a decline in oil and gas prices at the measurement date. The impairment was calculated based on December 31, 2008 spot prices of $44.60 per Bbl of oil and $5.62 per Mcf of gas. Based on these year-end prices, the effect of derivative contracts accounted for as cash flow hedges increased the full cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount. The qualifying cash flow hedges as of December 31, 2008, which consisted of commodity price swaps, covered 6,254 MBbls of oil production for the period from January 2009 through December 2013.

Prices have remained volatile subsequent to December 31, 2008. If prices remain at these low levels, we may be required to record additional write downs under the full cost ceiling test in the first quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of each period, the incremental proved reserves added during each period and additional capital spent.

• Monetization of Derivative Assets. During 2008, we monetized certain derivative instruments with original settlement dates from January through June of 2009. Net proceeds received from this monetization were $32.6 million. As of December 31, 2008, we have a net derivative asset of $205.7 million.

• Production Tax Credit.During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our expected return on the investment will be the 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, 2008, we had received $2.8 million of proceeds from the tax credits. Subsequent to December 31, 2008, we have received an additional $21.8 million of proceeds.

• Capital Expenditure Budget. To keep our 2009 exploration and development expenditures within cash flow, the 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

• Insurance proceeds. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. We currently estimate that the total costs attributable to the loss of well control will be approximately $12.5 million. We anticipate that our insurance policy will cover 100% of these costs up to a maximum of $35.0 million, with the $0.6 million insurance retention and deductible being

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payable by us. As of December 31, 2008, we received $8.1 million for costs incurred through August 9, 2008, and recorded the insurance proceeds as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows. We have submitted to our insurer additional claims totaling approximately $3.7 million for costs incurred through August 9, 2008.

• Private equity sale. On September 29, 2006, we sold an aggregate of 102,000 shares of our 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 owned properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations.

• 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 $23.6 million. 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 were used to pay down outstanding amounts under our Credit Agreement.

Liquidity and Capital Resources

Crude oil and natural gas prices have fallen significantly from their peak levels during the second and third quarters of 2008. Lower oil and gas prices decrease our revenues. An extended decline in oil or gas prices may materially and adversely affect our future business, liquidity or ability to finance planned capital expenditures. Lower oil and gas prices may also reduce the amount of our borrowing base under our Credit Agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and issuance of equity. At December 31, 2008, we had approximately $52.1 million of cash and cash equivalents and $3.3 million of availability under our revolving credit line with a borrowing base of $600.0 million.

Covenants set forth in the indentures for our 8 ¹/2% Senior Notes and the 8 ⁷/8% Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates. Based on the commodity prices for crude oil and natural gas at year end, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $320.0 million.

We believe that we will have sufficient funds available through our cash from operations to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months. We may adjust our planned capital expenditures depending on the timing and amount of any equity funding received and the availability of acquisition opportunities that meet our investment criteria.

We generally have had a working capital deficit as our capital expenditures have historically exceeded our cash flow; however, as a result of the current commodity pricing and its impact on our ability to utilize our revolving credit in 2009, we drew down substantially all our remaining availability under our Credit Agreement

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prior to December 31, 2008. Prior to year-end, we also monetized certain derivative instruments with original settlement dates from January through June of 2009, which generated net proceeds of $32.6 million. We have changed our cash management activities to target a minimum balance of cash on hand, which we expect to maintain in highly liquid investments.

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.

Sources and uses of cash. The net increase in cash is summarized as follows:

	Year Ended December 31,
(dollars in thousands)	2006			2007			2008
Cash flows provided by operating activities	$	89,154		$	113,443		$	146,914
Cash flows used in investing activities		(703,804	)		(239,442	)		(263,988	)
Cash flows provided by financing activities		621,855			128,883			157,499
Net increase in cash during the period	$	7,205		$	2,884		$	40,425

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. For the year ended December 31, 2008, cash flow from operating activities increased by approximately 30% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense and increased settlement losses on 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, 2008, the net cash provided from operations was approximately 56% of our net cash used in investing activities. Cash flow from operating activities and debt financing were primarily used during the year ended December 31, 2008 to fund $264.0 million in cash expenditures for investing activities.

Capital expenditures. For the year ended December 31, 2008, we incurred actual costs as summarized by area in the following table:

(Dollars in thousands)	For the year ended December 31, 2008(1)		Percent of total
Mid-Continent(2)	$	197,778	65	%
Permian Basin		65,714	22	%
Gulf Coast		22,795	7	%
Ark-La-Tex		5,232	2	%
North Texas		9,185	3	%
Rocky Mountains		1,972	1	%
	$	302,676	100	%

(1) Includes $0.7 million of additions relating to increases in our asset retirement obligations.

(2) Includes $16.1 million of costs related to the construction of a compressor station and CO₂ pipeline.

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In addition to the capital expenditures for oil and gas properties, we spent approximately $36.7 million for acquisition and construction of new office and administrative facilities and equipment during 2008.

Our actual costs incurred for the year ended December 31, 2008 and our current 2009 budgeted capital expenditures for oil and gas properties are detailed in the table below:

(Dollars in thousands)	For the year ended December 31, 2008(1)		2009 budgeted capital expenditures
Development activities:
Developmental drilling(2)	$	170,986	$	38,000
Enhancements		55,350		6,000
EOR		25,354		5,000
Acquisitions:
Proved properties		39,201		2,000
Unproved properties		6,677		—
Exploration activities		5,108		—
Total	$	302,676	$	51,000

(1) Includes $0.7 million of additions relating to increases in our asset retirement obligations.

(2) Includes $16.1 million of costs related to the construction of a compressor station and CO₂ pipeline which were not included in the budget.

Our 2009 budgeted capital expenditures for oil and gas properties summarized by area are detailed in the table below:

(Dollars in thousands)	2009 drilling capital expenditures		Percent of total
Mid-Continent	$	38,000	74	%
Permian Basin		12,000	24	%
Other		1,000	2	%
	$	51,000	100	%

A majority of our capital expenditure budget for development drilling in 2009 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. The 2009 capital budget represents an 83% reduction in capital expenditures from our 2008 levels. Despite this reduction, we expect production for 2009 to remain at levels comparable to 2008 as a result of capital investments made in 2008 and the first quarter of 2009. However, if conditions do not improve and we are unable to expand our capital expenditure budget in 2010, we would expect production to decline at a rate consistent with our production decline curve.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2009 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

Our existing credit facility. As of December 31, 2008, we had $594.0 million outstanding under our Credit Agreement and the borrowing base was $600.0 million. We believe we are in compliance with all covenants under the Credit Agreement as of December 31, 2008.

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In October 2006, we 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. The borrowing base, which was redetermined effective December 24, 2008, is $600.0 million as of December 31, 2008.

Interest is paid on $594.0 million based upon LIBOR as of December 31, 2008 (effective rate of 5.299%). The credit line is collateralized by our 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.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. At December 31, 2008, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined effective December 24, 2008, as the greater of 2% or 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 Credit Agreement, plus a margin where the margin varies from 2.000% to 3.750% depending on the utilization percentage of the conforming borrowing base. At December 31, 2008, the LIBOR rate, as defined, was 2.000%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 3.299% resulting in an effective interest rate of 5.299% 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.

Effective December 24, 2008, interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.125% to 2.875%, depending on the utilization percentage of the borrowing base.

Commitment fees of 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 borrowing base is subject to redetermination on May 1, 2009. 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.

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;

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• 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.

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 GAAP. 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, 2007 and 2008, our current ratio as computed using GAAP was 0.69 and 1.34, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.49 and 1.19, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:

(Dollars in thousands)	December 31, 2007			December 31, 2008
Current assets per GAAP	$	120,704		$	218,363
Plus—Availability under Credit Agreement		76,311			3,270
Less—Deferred tax asset on derivative instruments and asset retirement obligations		(19,123	)		—
Less—Short-term derivative instruments		—			(51,412	)
Current assets as adjusted	$	177,892		$	170,221
Current liabilities per GAAP	$	174,980		$	163,123
Less—Short-term derivative instruments		(54,307	)		—
Less—Deferred tax liability on derivative instruments and asset retirement obligations		—			(19,755	)
Less—Short-term asset retirement obligation		(1,000	)		(300	)
Current liabilities as adjusted	$	119,673		$	143,068
Current ratio for loan compliance		1.49			1.19

Our Credit Agreement is scheduled to mature on October 31, 2010. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability, and we may not meet the required Current Ratio, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

Prior to the amendment described below, the Credit Agreement required us to maintain 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;

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• 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.

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.

Based on our borrowings under our Credit Agreement of $594.0 million, to meet our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we will be required to achieve Consolidated EBITDAX, as defined in our Credit Agreement, of approximately $240.0 million for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters during the year ended December 31, 2009. We had Consolidated EBITDAX of approximately $280.2 million for the year ended December 31, 2008. Due to the significant decline in oil and gas prices, we may not generate the required $240.0 million of Consolidated EBITDAX in 2009. If we are not able to modify the referenced ratio or otherwise increase Consolidated EBITDAX, such as through the monetization of additional derivatives, we would not meet the covenants under our Credit Agreement, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

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

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• 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.

If our borrowing base amount is reduced by the banks, or if we expect to be unable to meet our required Current Ratio, or our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could reduce our debt amount by monetizing additional derivative contracts, selling nonproducing oil and gas assets, selling non-oil and gas assets, selling producing oil and gas assets or raising equity. There is no assurance, however, that we will be able to sell our assets or equity at commercially reasonable terms or that any sales would generate enough cash to adequately reduce the borrowing base or that we will be able to meet our future obligations to the banks.

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 is 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.

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.

As of December 31, 2008, we are not able to incur additional secured debt as a result of the ACNTA test under the 8 ¹/2% Senior Notes.

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

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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 is 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.

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.

As of December 31, 2008, we are not able to incur additional secured debt as a result of the ACNTA test under the 8 ⁷/8% Senior Notes.

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. If we failed to complete the exchange offer within 270 days after the closing date, we would 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 increased an additional 0.25% for each additional 90 days, up to a total of 1.0%. The exchange

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offer was not 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. Total liquidated damages paid in 2008 were $0.4 million.

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.

Contractual obligations. The following table summarizes our contractual obligations and commitments as of December 31, 2008:

(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	$	31,476	$	625,476	$	—	$	—	$	656,952
Senior notes, including estimated interest		56,469		112,938		112,938		796,587		1,078,932
Other long-term notes including estimated interest		7,558		10,089		4,520		18,260		40,427
Capital leases including estimated interest		259		304		—		—		563
Abandonment obligations		300		600		600		31,875		33,375
Derivative obligations		—		3,388		—		—		3,388
Purchase Commitments		2,847		3,969		—		—		6,816
Total	$	98,909	$	756,764	$	118,058	$	846,722	$	1,820,453

(1) As of December 31, 2008, we had no off-balance sheet arrangements.

We have long-term contracts to purchase up to all of the CO₂ manufactured at two existing ethanol plants. Based on plant capacity, it is estimated that we will purchase an average of approximately 4.2 MMcf per day over the ten-year contract term which will begin upon our first purchase, under one contract, and under the second contract an average of approximately 13.75 MMcf per day over the fifteen-year contract term which begins in 2009. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. We have rights under two additional 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. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase an average of approximately 16.0 MMcf per day over the remainder of the initial term of the contract, which expires in 2011. The contract automatically renews for an additional ten years unless terminated by us. We may also purchase a variable amount of CO₂ under the second contract and we are currently purchasing an average of approximately 5.0 MMcf per day and project our purchases to remain at that level through 2009. The contract expires in 2016. We may terminate this contract at the end of any calendar year with 13 months notice. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

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Comparison of Year Ended December 31, 2008 to Year Ended December 31, 2007

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)
	2007		2008
Oil and gas sales (dollars in thousands)
Oil	$	234,428	$	348,907	48.8	%
Gas		131,530		152,854	16.2	%
Total	$	365,958	$	501,761	37.1	%
Production
Oil (MBbls)		3,356		3,773	12.4	%
Gas (MMcf)		20,504		19,795	(3.5	)%
MMcfe		40,640		42,433	4.4	%
Average sales prices (excluding hedging)
Oil per Bbl	$	69.85	$	92.47	32.4	%
Gas per Mcf		6.41		7.72	20.4	%
Mcfe	$	9.00	$	11.82	31.3	%

Oil and gas revenues increased $135.8 million, or 37.1%, to $501.8 million during 2008 due to a 4.4% increase in sales volumes and a 31.3% increase in the average price per Mcfe. Oil and natural gas prices declined significantly during the fourth quarter of 2008. Based on our forecasted production, if oil and natural gas prices remain at current levels or decline further, our revenues in 2009 will be significantly lower than the amounts reported in 2008.

Oil sales increased 48.8% from $234.4 million to $348.9 million during the year ended December 31, 2008. This increase was due to a 12.4% increase in production volumes to 3,773 MBbls and a 32.4% increase in average oil prices to $92.47 per Bbl. Natural gas sales revenues increased 16.2% from $131.5 million for the year ended December 31, 2007 to $152.9 million for the year ended December 31, 2008. This increase was due to a 20.4% increase in average gas prices to $7.72 per Mcf, partially offset by a 3.5% decrease in production volumes to 19,795 MMcf. Oil production for the year ended December 31, 2008 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)
	2007	2008
Mid Continent	26,331	28,397	7.8	%
Permian Basin	6,284	6,871	9.3	%
Gulf Coast	3,787	3,383	(10.7	)%
Ark-La-Tex	1,905	1,746	(8.3	)%
North Texas	1,382	1,106	(20.0	)%
Rocky Mountains	951	930	(2.2	)%
Totals	40,640	42,433	4.4	%

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Our 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, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges. The effects of hedging on our net revenues for the years ended December 31, 2007 and 2008 are as follows:

	Year ended December 31,
(dollars in thousands)	2007			2008
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(19,797	)	$	(88,966	)
Hedge ineffectiveness		(8,343	)		12,549
Total	$	(28,140	)	$	(76,417	)

Our loss on hedge settlements was $89.0 million compared to a loss of $19.8 million in 2007, primarily due to high overall commodity prices during the first nine months of 2008. The loss on hedge settlements was partially offset by hedge ineffectiveness, which was a gain of $12.5 million in 2008 compared to a loss of $8.3 million in 2007. This was primarily due to lower NYMEX forward strip oil prices at December 31, 2008 compared to December 31, 2007, combined with higher average contractual prices.

During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding natural gas swaps. The $5.8 million cumulative change in fair value attributable to the natural gas swaps that had been accounted for as cash flow hedges and were outstanding as of December 31, 2008 has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income, and the ineffective portion would have been included in the loss from oil and gas hedging activities, which is a component of revenue.

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(1)
Oil (per Bbl):
Year ended December 31, 2007	$	69.85	$	61.35	87.8	%
Year ended December 31, 2008		92.47		73.08	79.0	%
Gas (per Mcf):
Year ended December 31, 2007	$	6.41	$	6.84	106.7	%
Year ended December 31, 2008		7.72		6.92	89.6	%

(1) Average realized prices only include the effects of hedging contracts that qualify and are designated for hedge accounting. Had we included the effects of contracts not so designated, our average realized price for oil would have been $61.35 and $71.95 per Bbl for 2007 and 2008, respectively, and our average realized price for gas would have been $6.80 and $7.38 per Mcf for 2007 and 2008, respectively.

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Costs and Expenses. The following table presents information about our operating expenses for each of the years ended December 31, 2007 and 2008:

	Amount						Per Mcfe
	Year ended December 31,				Percent Increase		Year ended December 31,				Percent Increase (Decrease)
(dollars in thousands)	2007		2008				2007		2008
Lease operating expenses	$	104,469	$	120,487	15.3	%	$	2.57	$	2.84	10.5	%
Production taxes		26,216		33,815	29.0	%		0.65		0.80	23.1	%
Depreciation, depletion and amortization		85,431		100,528	17.7	%		2.10		2.37	12.9	%
General and administrative		21,838		22,370	2.4	%		0.54		0.53	(1.9	)%

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. 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 during the first nine months of 2008. Included in the figures are a $4.7 million increase in electricity and fuel costs and a $2.4 million increase in workover activity. We expect lease operating expenses to decrease in the future if oil and gas prices remain at their current levels or decline further. However, the timing of the expected cost decline is uncertain, and we do not expect it to be proportional to the decline in our average realized prices.

Production taxes (which include ad valorem taxes)—Increase was primarily due to 31.3% higher average realized prices, and an increase of 4.4% increase in production volumes.

Depreciation, depletion and amortization—Increase was due primarily to an increase in DD&A on oil and gas properties of $12.6 million. For oil and gas properties, $3.9 million of the increase was due to higher production volumes in 2008 and $8.7 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 $0.21 to $2.15 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

Impairment of oil and natural gas properties— 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 our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the fourth quarter of 2008, we recorded a ceiling test impairment of oil and natural gas properties of $281.4 million as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 spot prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. Based on these year-end prices, the effect of derivative contracts accounted for as cash flow hedges increased the full-cost ceiling by $192.1 million, thereby reducing the ceiling test write down by the same amount. The qualifying cash flow hedges as of December 31, 2008, which consisted of commodity price swaps, covered 6,254 MBbls of oil production for the period from January 2009 through December 2013.

Prices have remained volatile subsequent to December 31, 2008. If prices remain at these low levels, we may be required to record additional write-downs under the full cost ceiling test in the first quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and natural gas prices at the end of each period, the incremental proved reserves added during each period and additional capital spent.

Impairment of ethanol plant—We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol LLC. The City of Blackwell has also been unable to obtain financing for the railroad upgrades and

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storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we would be unlikely to obtain equity capital or new project financing for an ethanol plant. We accordingly recorded an impairment charge of $2.9 million, which was the amount of our investment in the ethanol plant.

General and administrative expenses—G&A expense is net of $11.2 million in 2008 and $10.8 million in 2007 capitalized as part of our exploration and development activities.

Interest expense. Interest expense decreased by $1.6 million, or 1.8%, compared to 2007, primarily as a result of lower interest rates paid, somewhat offset by increased levels of borrowings. The following table presents interest expense:

(dollars in thousands)	2007		2008
Revolver Interest	$	27,387	$	23,574
8 1/2% Senior Notes, due 2015		28,285		28,348
8 7/8% Senior Notes, due 2017		28,413		29,578
Other Interest		3,571		4,538
	$	87,656	$	86,038

Non-hedge derivative gains (losses). Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:

	Year ended December 31,
(dollars in thousands)	2007			2008
Non-hedge derivative gains (losses):
Non-qualified commodity price swaps	$	(24,416	)	$	29,367
Non-designated costless collars		—			90,525
Natural gas basis differential contracts		635			7,049
Total	$	(23,781	)	$	126,941

During 2008, we entered into costless collars with a weighted average floor of $104.36 covering 1,846 MBbls of oil from July 2008 through December 2013. We also entered into costless collars with a weighted average floor of $10.00 covering 7,520 BBtu of gas from November 2008 through December 2010. Due to the decline in the NYMEX forward strip oil and gas prices, we recognized a gain on the collars of $90.5 million for the year ended December 31, 2008.

In December 2008, we monetized oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. Certain swaps that were settled had previously been accounted for as cash flow hedges. The $17.9 million cumulative change in fair value attributable to the swaps that had been accounted for as cash flow hedges has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold.

Primarily as a result of the above transactions, we had non-hedge derivative gains of $126.9 million for the year ended December 31, 2008 compared to non-hedge derivative losses of $23.8 million in 2007.

Termination fee and acquisition costs. On July 14, 2008, we entered into an Agreement and Plan of Merger (“Merger Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge would merge with and into our wholly owned subsidiary, Chaparral Exploration, L.L.C. During the fourth quarter of 2008, the parties concluded that it was highly unlikely that all of the closing conditions set forth in the Merger Agreement would be met, and therefore the merger would not be consummated on or prior to December 31, 2008, the date on which either party could, subject to the terms of the Merger Agreement, terminate the

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Merger Agreement unilaterally. As a result, we and Edge executed a Merger Termination Agreement on December 16, 2008, and costs of $1.4 million associated with the merger were expensed.

On July 14, 2008, we entered into a Stock Purchase Agreement with Magnetar Financial LLC (“Magnetar”), which provided for Magnetar and its affiliates to purchase 1.5 million shares of our Series B convertible preferred stock for an aggregate purchase price of $150.0 million. On December 16, 2008, we executed a Termination and Settlement Agreement (the “Magnetar Termination Agreement”) with Edge and Magnetar, which terminated the Stock Purchase Agreement. Pursuant to the Magnetar Termination Agreement, Magnetar paid a total of $5.0 million, of which $1.5 million was paid to Edge at our direction to reimburse Edge for certain expenses, and $3.5 million was paid to us and recorded as a termination fee.

Service company revenues and operating expenses. Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, Inc., 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 $34.3 million in service company revenue in the year ended December 31, 2008, with corresponding service company expense of $31.7 million, for a net profit of $2.6 million. Service company revenue before intercompany eliminations was $72.9 million and a pre-tax net profit of $5.6 million in the year ended December 31, 2008. We recognized $20.6 million in service company revenue in the year ended December 31, 2007 with corresponding service company expense of $18.8 million, for a net profit of $1.8 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.

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.

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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	%
Rocky Mountains	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	)

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(1)
Oil (per Bbl):
Year ended December 31, 2006	$	61.65	$	46.99	76.2	%
Year ended December 31, 2007		69.85		61.35	87.8	%
Gas (per Mcf):
Year ended December 31, 2006	$	6.29	$	6.52	103.7	%
Year ended December 31, 2007		6.41		6.84	106.7	%

(1) Average realized prices only include the effects of hedging contracts that qualify and are designated for hedge accounting. Had we included the effects of contracts not so designated, our average realized price for gas would have been $6.52 and $6.80 per Mcf for 2006 and 2007, respectively.

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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		85,431	63.4	%		1.61		2.10	30.4	%
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 25.5% increase in production volumes and a 17.0% increase in average realized 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 Plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.3 million of the increase was due to the revision in the Phantom 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.

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:

(dollars in thousands)	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

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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 $18.8 million, for a net profit of $1.8 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 2006.

Critical accounting policies and estimates

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

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and 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 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, (“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 the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Loss from oil and gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Loss from oil and gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. As a result, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using

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internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with SFAS No. 157, Fair Value Measurements (“SFAS 157”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2 in accordance with SFAS 157. We determine fair value for our oil and gas collars using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3 in accordance with SFAS 157. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

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., Ryder Scott Company, L.P., and Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 75% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2008, 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%, adjusted for the impact of derivatives accounted for as cash flow hedges, plus the lower of cost or fair market value of unevaluated properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues are those in effect as of the last day of the quarter. If oil and gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that additional 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, 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

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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 and FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

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

Recent accounting pronouncements

In 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

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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. We intend to adopt SFAS 141(R) effective January 1, 2009 and apply its provisions prospectively.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51(“SFAS 160”).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 for financial statements issued for fiscal years and interim periods beginning after December 15, 2008. We are 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”). SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133 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. We are currently assessing the impact, if any, of the adoption of SFAS 161.

In December 2008, the Securities and Exchange Commission (“SEC”) issued Release No. 33-8995,Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently, the SEC requires that reserve volumes be determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the first day of each month for the prior twelve-month period rather than year-end prices. The new requirements will also allow companies to disclose their probable and possible reserves to investors, and will require them to report the independence and qualifications of their reserves preparer or auditor. The new rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We will adopt the provisions of the new rule in connection with our December 31, 2009 Form 10-K filing. We are currently evaluating the impact of the rule on our financial statements.

Effects of inflation and pricing

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

59

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, 2008 production, our gross revenues from oil and gas sales would change approximately $2.0 million for each $0.10 change in gas prices and $3.8 million for each $1.00 change in oil prices.

To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, 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 offset, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges pursuant to SFAS 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

We use basis protection swaps 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 pricing 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. We do not believe that these instruments qualify as hedges pursuant to SFAS 133; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

In anticipation of the Calumet acquisition, we entered into additional commodity swaps to provide protection against a decline in the price of oil. We do not believe that these instruments qualify as hedges pursuant to SFAS 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. As of December 31, 2008, the hedges assumed as part of the Calumet acquisition have been settled.

60

Our outstanding oil and gas derivative instruments as of December 31, 2008 are summarized below:

	Crude Oil Swaps						Crude Oil Collars
	Hedge			Non-hedge			Non-hedge
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range to be received		Percent of PDP production(1)
1Q 2009	159	$	72.06	21	$	66.78	30	$	110.00 -$169.15	23.7	%
2Q 2009	153		71.09	—		—	30		110.00 -  169.15	21.5	%
3Q 2009	480		68.81	90		66.57	60		110.00 -  164.28	76.4	%
4Q 2009	471		68.25	90		66.18	60		110.00 -  164.28	77.6	%
1Q 2010	420		67.40	102		65.80	60		110.00 -  168.55	75.3	%
2Q 2010	420		67.10	90		65.47	60		110.00 -  168.55	76.0	%
3Q 2010	408		66.43	90		65.10	60		110.00 -  168.55	80.2	%
4Q 2010	402		65.95	90		64.75	60		110.00 -  168.55	81.2	%
1Q 2011	309		64.40	99		64.24	51		110.00 -  152.71	69.2	%
2Q 2011	309		64.06	90		63.93	51		110.00 -  152.71	69.4	%
3Q 2011	309		63.71	90		63.61	51		110.00 -  152.71	70.9	%
4Q 2011	309		63.33	90		63.30	51		110.00 -  152.71	72.6	%
1Q 2012	281		124.66	—		—	157		100.00 -  135.25	72.2	%
2Q 2012	275		124.63	—		—	154		100.00 -  135.25	72.6	%
3Q 2012	271		124.61	—		—	152		100.00 -  135.25	72.9	%
4Q 2012	265		124.60	—		—	149		100.00 -  135.25	72.8	%
1Q 2013	262		124.44	—		—	110		100.00 -  133.50	66.5	%
2Q 2013	256		124.44	—		—	110		100.00 -  133.50	66.7	%
3Q 2013	250		124.45	—		—	107		100.00 -  133.50	66.1	%
4Q 2013	245		124.47	—		—	103		100.00 -  133.50	65.7	%
	6,254			942			1,666

	Natural Gas Swaps			Natural Gas Collars			Percent of PDP production(1)
	Non-hedge			Non-hedge
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range to be received
1Q  2009	750	$	7.74	600	$	10.00 -$14.06	18.6	%
2Q  2009	750		7.47	600		10.00 -  14.06	19.4	%
3Q  2009	3,390		7.19	990		10.00 -  13.85	67.3	%
4Q  2009	3,300		7.66	990		10.00 -  13.85	69.9	%
1Q  2010	2,550		7.78	840		10.00 -  11.53	58.3	%
2Q  2010	2,550		7.08	840		10.00 -  11.53	62.2	%
3Q  2010	2,550		7.30	840		10.00 -  11.53	68.1	%
4Q  2010	2,550		7.72	840		10.00 -  11.53	72.0	%
1Q  2011	1,800		7.89	—		—	40.1	%
2Q  2011	1,800		7.02	—		—	42.0	%
3Q  2011	1,800		7.19	—		—	43.7	%
4Q  2011	1,800		7.54	—		—	45.5	%
	25,590			6,540

61

	Natural Gas Basis Protection Swaps
	Non-hedge
	Volume BBtu	Weighted average fixed price to be paid
1Q 2009	5,220	$	1.02
2Q 2009	5,160		0.90
3Q 2009	4,620		0.91
4Q 2009	4,440		0.94
1Q 2010	4,350		0.96
2Q 2010	1,500		0.88
3Q 2010	1,500		0.88
4Q 2010	1,500		0.91
1Q 2011	1,500		0.93
	29,790

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

Subsequent to December 31, 2008, we entered into the following derivative instruments:

	Crude Oil Swaps			Natural Gas Swaps			Natural Gas Basis Protection Swaps
	Hedge			Non-hedge			Non-hedge
	Volume MBbl	Weighted average fixed price to be received		Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average fixed price to be paid
1Q 2009	—	$	—	2,000	$	5.60	—	$	—
2Q 2009	240		54.02	3,000		5.73	—		—
3Q 2009	28		57.99	300		6.46	—		—
4Q 2009	19		60.86	300		7.04	—		—
1Q 2010	—		—	600		7.50	—		—
2Q 2010	—		—	600		6.91	750		0.72
3Q 2010	—		—	600		7.14	750		0.72
4Q 2010	—		—	600		7.55	950		0.68
1Q 2011	—		—	600		7.98	1,050		0.66
2Q 2011	—		—	600		7.05	—		—
3Q 2011	—		—	600		7.21	—		—
4Q 2011	—		—	600		7.56	—		—
	287			10,400			3,500

On March 27, 2009, we monetized natural gas swaps of 1,100 BBtu per month for May and June 2009, and 700 BBtu per month for July through October 2009, resulting in cash proceeds of approximately $9.5 million. These swaps were with two different counterparties, and were put into place after our last borrowing base redetermination; therefore, they were not incorporated into the determination of the borrowing base.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of December 31, 2008 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 $600.0 million, equal to our borrowing base at December 31, 2008, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 million.

62

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	64
Consolidated balance sheets as of December 31, 2007 and 2008	65
Consolidated statements of operations for the years ended December 31, 2006, 2007 and 2008	66
Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December  31, 2006, 2007 and 2008	67
Consolidated statements of cash flows for the years ended December 31, 2006, 2007 and 2008	68
Notes to consolidated financial statements	70

63

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, 2007 and 2008, 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, 2008. 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, 2007 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

/s/    GRANT THORNTON LLP        

Oklahoma City, Oklahoma

March 31, 2009

64

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	December 31,
(dollars in thousands, except per share data)	2007			2008
Assets
Current assets:
Cash and cash equivalents	$	11,687		$	52,112
Accounts receivable, net		65,292			69,562
Production tax benefit		813			13,685
Inventories		19,480			27,143
Deferred income taxes		19,128			—
Prepaid expenses		4,304			4,449
Derivative instruments		—			51,412
Total current assets		120,704			218,363
Property and equipment—at cost, net		50,747			72,891
Oil & gas properties, using the full cost method:
Proved		1,457,822			1,751,096
Unproved (excluded from the amortization base)		25,327			16,865
Work in progress (excluded from the amortization base)		19,274			31,893
Accumulated depreciation, depletion, amortization and impairment		(200,577	)		(573,233	)
Total oil & gas properties		1,301,846			1,226,621
Funds held in escrow		5,224			2,350
Derivative instruments		—			157,720
Other assets		52,377			34,891
	$	1,530,898		$	1,712,836
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	68,241		$	92,777
Accrued payroll and benefits payable		9,299			9,215
Accrued interest payable		14,741			15,408
Revenue distribution payable		21,471			19,827
Current maturities of long-term debt and capital leases		6,921			6,200
Derivative instruments		54,307			—
Deferred income taxes		—			19,696
Total current liabilities		174,980			163,123
Long-term debt and capital leases, less current maturities		459,826			617,714
8 1/2% Senior Notes, due 2015		325,000			325,000
8 7/8% Senior Notes, due 2017		322,490			322,675
Derivative instruments		96,227			3,388
Deferred compensation		2,017			762
Asset retirement obligations		29,684			33,075
Deferred income taxes		17,496			42,699
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, 2007 and 2008, respectively		9			9
Additional paid in capital		100,918			100,918
Retained earnings		76,090			21,340
Accumulated other comprehensive income (loss), net of taxes		(73,839	)		82,133
		103,178			204,400
	$	1,530,898		$	1,712,836

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

65

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Year Ended December 31,
(dollars in thousands, except per share data)	2006			2007			2008
Revenues:
Oil and gas sales	$	249,180		$	365,958		$	501,761
Loss from oil and gas hedging activities		(4,166	)		(28,140	)		(76,417	)
Service company sales		—			20,611			34,272
Total revenues		245,014			358,429			459,616
Costs and expenses:
Lease operating		71,663			104,469			120,487
Production taxes		18,710			26,216			33,815
Depreciation, depletion and amortization		52,299			85,431			100,528
Loss on impairment of oil & gas properties		—			—			281,393
Loss on impairment of ethanol plant		—			—			2,900
General and administrative		14,659			21,838			22,370
Service company expenses		—			18,852			31,656
Total costs and expenses		157,331			256,806			593,149
Operating income (loss)		87,683			101,623			(133,533	)
Non-operating income (expense):
Interest expense		(45,246	)		(87,656	)		(86,038	)
Non-hedge derivative gains (losses)		(4,677	)		(23,781	)		126,941
Termination fee		—			—			3,500
Merger costs		—			—			(1,400	)
Other income		792			2,276			1,394
Net non-operating income (expense)		(49,131	)		(109,161	)		44,397
Income (loss) before income taxes and minority interest		38,552			(7,538	)		(89,136	)
Income tax expense (benefit)		14,817			(2,745	)		(34,386	)
Minority interest		(71	)		—			—
Net income (loss)	$	23,806		$	(4,793	)	$	(54,750	)
Net income (loss) per share (basic and diluted)	$	29.74		$	(5.47	)	$	(62.43	)
Weighted average number of shares used in calculation of basic and diluted earnings per share		800,500			877,000			877,000

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

66

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

and comprehensive income (loss)

(dollars in thousands)	Common stock			Additional paid in capital		Retained earnings			Accumulated other comprehensive income (loss)			Total
	Shares	Amount
Balance at January 1, 2006	775,000	$	8	$	—	$	58,126		$	(47,967	)	$	10,167
Issuance of common stock	102,000		1		100,918		—			—			100,919
Dividends	—		—		—		(1,049	)		—			(1,049	)
Net income	—		—		—		23,806			—			23,806
Other comprehensive income, net
Unrealized gain on hedges, net of taxes of $18,916	—		—		—		—			29,949			29,949
Reclassification adjustment for hedge losses included in net income, net of taxes of $8,855	—		—		—		—			14,072			14,072
Total comprehensive income													67,827
Balance at December 31, 2006	877,000		9		100,918		80,883			(3,946	)		177,864
Net loss	—		—		—		(4,793	)		—			(4,793	)
Other comprehensive loss, net
Unrealized loss on hedges, net of taxes of $51,745	—		—		—		—			(82,032	)		(82,032	)
Reclassification adjustment for hedge losses included in net loss, 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
Net loss	—		—		—		(54,750	)		—			(54,750	)
Other comprehensive income, net
Unrealized gains on hedges, net of taxes of $64,045	—		—		—		—			101,347			101,347
Reclassification adjustment for hedge losses included in net loss, net of taxes of $34,341	—		—		—		—			54,625			54,625
Total comprehensive income													101,222
Balance at December 31, 2008	877,000	$	9	$	100,918	$	21,340		$	82,133		$	204,400

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

67

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Year Ended December 31,
(dollars in thousands)	2006			2007			2008
Cash flows from operating activities
Net income (loss)	$	23,806		$	(4,793	)	$	(54,750	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion & amortization		52,299			85,431			100,528
Service company depreciation, depletion & amortization		—			411			1,445
Loss on impairments		—			—			284,293
Deferred income taxes		14,839			(2,729	)		(34,358	)
Unrealized (gain) loss on ineffective portion of hedges		(18,761	)		8,343			(12,549	)
Change in fair value of non-hedge derivative instruments		4,681			23,781			(126,941	)
Gain on sale of assets		(132	)		(712	)		(177	)
Other		1,266			1,404			2,750
Change in assets & liabilities, net of assets and liabilities of business acquired
Accounts receivable		(13,213	)		(13,660	)		(2,516	)
Inventories		(444	)		3,568			(8,278	)
Prepaid expenses and other assets		376			(1,079	)		1,373
Accounts payable and accrued liabilities		16,659			8,426			(1,957	)
Revenue distribution payable		7,696			4,221			(1,643	)
Deferred compensation		82			831			(306	)
Net cash provided by operating activities		89,154			113,443			146,914
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(201,256	)		(220,651	)		(304,568	)
Acquisition of a business, net of cash acquired		(466,656	)		(21,569	)		—
Proceeds from dispositions of property and equipment and oil and gas properties		5,820			526			1,808
Cash in escrow		(21,795	)		(2,156	)		1,385
Proceeds from sale of a business		—			3,158			—
Purchase of prepaid production tax asset		(15,000	)		—			—
Settlement of non-hedge derivative instruments		(85	)		(750	)		37,387
Other		(4,832	)		2,000			—
Net cash used in investing activities		(703,804	)		(239,442	)		(263,988	)
Cash flows from financing activities
Proceeds from long-term debt		629,936			119,865			162,511
Repayment of long-term debt		(100,199	)		(304,240	)		(5,692	)
Proceeds from equity issuance		100,919			—			—
Proceeds from senior notes		—			322,329			—
Principal payments under capital lease obligations		(148	)		(171	)		(244	)
Dividends		(1,049	)		—			—
Settlement of derivative instruments acquired		876			(1,898	)		184
Fees paid related to financing activities		(8,107	)		(7,002	)		(1,360	)
Proceeds from termination fee		—			—			3,500
Fees paid related to IPO and merger activities		(373	)		—			(1,400	)
Net cash provided by financing activities		621,855			128,883			157,499
Net increase in cash and cash equivalents		7,205			2,884			40,425
Cash and cash equivalents at beginning of period		1,598			8,803			11,687
Cash and cash equivalents at end of period	$	8,803		$	11,687		$	52,112
Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	44,068		$	73,892		$	82,334
Income taxes		(22	)		(16	)		(28	)

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

68

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(continued)

Supplemental disclosure of investing and financing activities

During the years ended December 31, 2006, 2007, and 2008 the Company entered into capital lease obligations of $140, $21, and $592, respectively, for machinery and equipment.

Non-cash additions to oil and gas properties include $7,317, $24,527, and $25,407, respectively, as of December 31, 2006, 2007, and 2008. These oil and gas property additions are reflected in cash used in investing activities in the periods that the payables are settled. Also, non-cash additions to oil and gas properties for 2007 include $15,597 related to final settlement of the Calument acquisition. Non-cash additions to property and equipment for 2008 also include $1,707 related to final settlement of the Green Country Supply acquisition.

During the years ended December 31, 2006, 2007, and 2008, the Company recorded an asset and related liability of $10,813, $266 and $707, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $1,001, $1,613, and $1,370 was capitalized during the years ended December 31, 2006, 2007, and 2008, respectively, related to unproved oil and gas leaseholds. Interest of $0, $70, and $225 was capitalized during the years ended December 31, 2006, 2007, and 2008, respectively, primarily related to the construction of the Company’s office building.

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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.

In addition, Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary, provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

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

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.

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.

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation.

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. As of December 31, 2008, cash and escrow cash with a recorded balance totaling $49,051 was held at JP Morgan Chase Bank, N.A. 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 natural gas purchasers which are generally uncollateralized. The Company generally reviews its oil and natural gas purchasers for credit worthiness and general financial condition. The Company may have the ability to withhold future revenue

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disbursements to recover non-payment of joint interest billings on properties of which the Company is the operator. 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, 2007 and 2008 were $1,060 and $1,124, respectively. The Company determines its allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and gas properties operated by the Company and the owner’s ability to pay its obligation, among other things.

The Company writes off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2006, 2007, and 2008 was $553, $14, and $729, 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 the allowance for doubtful accounts. Accounts receivable consisted of the following at December 31:

	2007			2008
Joint interests	$	19,845		$	21,136
Accrued oil and gas sales		40,377			27,432
Service company sales		4,827			5,912
Hedge settlements		51			15,315
Other		530			654
Allowance for doubtful accounts		(338	)		(887	)
	$	65,292		$	69,562

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 average cost method. 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. The provision for excess or obsolete inventory for the years ended December 31, 2006, 2007, and 2008 was $115, $136, and $615, respectively. Inventories at December 31, 2007 and 2008 consist of the following:

	December 31, 2007			December 31, 2008
Equipment inventory	$	3,027		$	10,484
Oil and gas product		3,221			3,467
Service company inventory for resale		15,982			15,904
Inventory valuation allowance		(2,750	)		(2,712	)
	$	19,480		$	27,143

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

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

Depreciation, depletion and amortization of oil and gas properties are provided using the units-of-production method based on estimates of proved oil and gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. The Company’s cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment. Depreciation, depletion and amortization expense of oil and gas properties was $47,086, $78,717, and $91,316 for the years ended December 31, 2006, 2007, and 2008, respectively.

In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for the Company’s cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the fourth quarter of 2008, the Company recorded a ceiling test impairment of oil and gas properties of $281,393 as a result of a decline in oil and gas prices at the measurement date. The impairment was calculated based on December 31, 2008 spot prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. Based on these year-end prices, the effect of derivative contracts accounted for as cash flow hedges increased the full cost ceiling by $192,108, thereby reducing the ceiling test write down by the same amount. The qualifying cash flow hedges as of December 31, 2008, which consisted of commodity price swaps, covered 6,254 MBbls of oil production for the period from January 2009 through December 2013. See Note 4 for a further discussion of hedging activity.

Prices have remained volatile subsequent to December 31, 2008. If prices remain at these low levels, we may be required to record additional write downs under the full cost ceiling test in the first quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of each period, the incremental proved reserves added during each period, and additional capital spent.

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 the 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, 2007, a production tax benefit asset of $14,255 was included in other assets in the consolidated balance sheet. As of December 31, 2008, the carrying value was $13,685. Of the $1,490 approved for payment in 2007, $745 was recognized as income and $745 as a reduction of the asset. Of the $1,422 approved for payment in 2008, $711 was recognized as income and $711 as a reduction of the asset. Subsequent to December 31, 2008, we have received an additional $21,843 of proceeds from the tax benefit asset.

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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:

	2007		2008
Escrows from acquisitions	$	383	$	692
Plugging and abandonment escrow		1,635		1,658
Post closing adjustment escrow from acquisition		3,206		—
	$	5,224	$	2,350

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.

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.

We owned a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. Oklahoma Ethanol LLC retained a financial advisor to arrange project financing to fund construction costs and for related start-up working capital. Because financing did not close by September 15, 2008, the minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participate in the joint venture, and we now own 100% of Oklahoma Ethanol LLC. The City of Blackwell has also been unable to obtain financing for the railroad upgrades and storage facilities that would be necessary to support ethanol production. During the third quarter of 2008, we determined that we will be unlikely to obtain equity capital or new project financing for an ethanol plant, and accordingly recorded an impairment charge of $2,900, which was the amount of our investment in the ethanol plant.

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.

The Company accounts for uncertain tax positions in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 48,Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109 (“FIN 48”). If applicable, we would report a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2007 and 2008, we have not recorded a liability or accrued interest related to uncertain tax positions.

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The tax years 1998 through 2008 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 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 1,903 million cubic feet (MMcf), 1,961 MMcf, and 1,840 MMcf at December 31, 2006, 2007, and 2008, respectively. The Company’s aggregate imbalance due to under production is approximately 3,331 MMcf, 3,170 MMcf, and 3,194 MMcf at December 31, 2006, 2007, and 2008, respectively.

Derivative transactions

The Company uses derivative instruments 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 (as Amended),Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). SFAS 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.

Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the statement of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the statement of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is 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, is immediately recognized in loss from oil and gas hedging activities in the statement of operations. Cash flows associated with hedges are reported as operating activities in the statement of cash flows unless the hedges contain a significant financing element, in which case they are reported as financing activities.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.

In accordance with FASB Interpretation No. 39 (As Amended),Offsetting of Amounts Related to Certain Contracts, the Company offsets assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement.

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Fair value measurements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which addresses how companies should measure fair value when they are required to use a fair value measure for recognition or disclosure purposes under GAAP. SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

We adopted the provisions of SFAS 157 on January 1, 2008. Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined in SFAS 157. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives.

We elected to implement this Statement with the one-year deferral permitted by FASB Staff Position 157-2,Effective Date of FASB Statement No. 157(“FSP 157-2”), for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). The deferral applies to nonfinancial assets and liabilities measured at fair value in a business combination; impaired properties, plants and equipment; intangible assets and goodwill; and initial recognition of asset retirement obligations and restructuring costs for which we use fair value. We do not expect any significant impact to our consolidated financial statements when we implement SFAS 157 for these assets and liabilities. Due to our election under FSP 157-2, for 2008, SFAS 157 applies to our commodity derivative contracts. The implementation of SFAS 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating the impact of nonperformance risk on derivative instruments. The primary impact from adoption was additional disclosures.

In October 2008, the FASB issued FSP 157-3,Estimating the Fair Value of a Financial Asset in a Market That Is Not Active (“FSP 157-3”), which provides guidance regarding how to determine the fair value of a financial asset when there is no active market for the asset at the measurement date. FSP 157-3 clarifies how management’s internal assumptions should be considered in measuring fair value when observable data are not present. In addition, observable market information from an inactive market should be considered to determine fair value, and it is inappropriate to conclude that all market activity represents forced liquidations or distressed sales or to conclude that any transaction price can determine fair value. The use of broker quotes and pricing services should also be considered to assess the relevance of observable and unobservable data. When valuing financial assets and liabilities, significant judgment is required. FSP 157-3 is effective upon issuance and has been considered in conjunction with our year 2008 financial reporting and results. There was no material impact on our financial position or results of operations for the year ended December 31, 2008.

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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 159”), which permits companies to choose to measure certain financial instruments and other items at fair value. Unrealized gains and losses on any items for which the Company elects the fair value measurement option would be reported in earnings. We adopted the provisions of SFAS 159 on January 1, 2008. We have elected not to present assets and liabilities at fair value that were not required to be measured at fair value prior to the adoption of SFAS 159.

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.

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.

Comprehensive income (loss)

Comprehensive income (loss) consists of net income (loss) and the unrealized gain or loss for the effective portion of derivative instruments classified as cash flow hedges. Comprehensive income (loss) is presented net of income taxes in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss).

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, 2007 and 2008, 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.

Termination fee and acquisition costs

On July 14, 2008, we entered into an Agreement and Plan of Merger (“Merger Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge would merge with and into our wholly owned subsidiary, Chaparral Exploration, L.L.C. During the fourth quarter of 2008, the parties concluded that it was highly unlikely that all of the closing conditions set forth in the Merger Agreement would be met, and therefore the merger would not be consummated, on or prior to December 31, 2008, the date on which either party could, subject to the terms of the Merger Agreement, terminate the Merger Agreement unilaterally. As a result, the Company and Edge executed a Merger Termination Agreement on December 16, 2008, and costs of $1,400 associated with the merger were expensed.

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On July 14, 2008, we entered into a Stock Purchase Agreement with Magnetar Financial LLC (“Magnetar”), which provided for Magnetar and its affiliates to purchase 1.5 million shares of Series B convertible preferred stock of the Company for an aggregate purchase price of $150,000. On December 16, 2008, we executed a Termination and Settlement Agreement (the “Magnetar Termination Agreement”) with Edge and Magnetar, which terminated the Stock Purchase Agreement. Pursuant to the Magnetar Termination Agreement, Magnetar paid a total of $5,000, of which $1,500 was paid to Edge at our direction to reimburse Edge for certain expenses, and $3,500 was paid to us and recorded as a termination fee.

Recent accounting pronouncements

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 intends to adopt SFAS 141(R) effective January 1, 2009 and apply its provisions prospectively.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51(“SFAS 160”).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 for financial statements issued for fiscal years and interim periods 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”). SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133 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. The Company is currently assessing the impact, if any, of the adoption of SFAS 161.

In December 2008, the SEC issued Release No. 33-8995,Modernization of Oil and Gas Reporting, which revises disclosure requirements for oil and gas companies. The new disclosure requirements permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new disclosure requirements also require companies to include nontraditional resources such as oil sands, shale, coalbeds or other nonrenewable natural resources in reserves if they are intended to be upgraded to synthetic oil and gas. Currently the SEC requires that reserve volumes are determined using prices on the last day of the reporting period; however, the new disclosure requirements provide for reporting oil and gas reserves using an average price based upon the first day of each month for the prior twelve months rather than year-end prices. The new requirements will also allow companies to disclose their probable and possible reserves to investors, and will require them to report the independence and qualifications of their reserves preparer or auditor. The new rule is effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the new rule. We will adopt the provisions of the new rule in connection with our December 31, 2009 Form 10-K filing. We are currently evaluating the impact of the rule on our financial statements.

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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 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 $14,406 due from the previous owners related to working capital at the time of acquisition. The amount 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 and 2008. The estimated receivable may differ from the final settlement amount.

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 and 2008, the escrow was $383 and $391, respectively, 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 and 2008, the Company has recorded an estimated liability of $4,378 related to the election. The estimated payable may differ from the final settlement amount. 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 approximately $23,606. 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.

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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. The purchase price allocation was finalized, and escrow amounts disbursed, during 2008. The final purchase price allocation is shown below:

	GCS
Calculation and allocation of purchase price:
Cash payment	$	25,000
Retained purchase price		(1,394	)
Total purchase price		23,606
Plus fair value of liabilities assumed:
Accounts payable and accrued expenses		6,739
Total purchase price plus liabilities assumed	$	30,345
Fair value of assets acquired:
Current assets, including cash of $348	$	24,821
Property and equipment		4,467
Intangible assets		1,057
Total fair value of assets acquired	$	30,345

The intangible assets primarily consist of fair value of customer lists which are being amortized over 48 months.

Note 3: Property and equipment

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

	2007		2008
Furniture and fixtures	$	1,437	$	1,720
Automobiles and trucks		11,559		14,252
Machinery and equipment		19,253		41,782
Office and computer equipment		6,006		7,464
Building and improvements		13,532		23,968
		51,787		89,186
Less accumulated depreciation and amortization		14,622		22,152
		37,165		67,034
Work in progress		8,552		53
Land		5,030		5,804
	$	50,747	$	72,891

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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:

	2007		2008
Office and computer equipment	$	1,783	$	1,926
Machinery and equipment		82		531
		1,865		2,457
Less accumulated depreciation and amortization		1,675		1,756
	$	190	$	701

Note 4: Derivative activities and financial instruments

Derivative activities

Our 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, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, 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 offset, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. Our collars have not been designated as hedges pursuant to SFAS 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

We use basis protection swaps 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 pricing 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. We do not believe that these instruments qualify as hedges pursuant to SFAS 133; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

In anticipation of the Calumet acquisition, we entered into additional commodity swaps to provide protection against a decline in the price of oil. We do not believe that these instruments qualify as hedges pursuant to SFAS 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

As part of the Calumet acquisition, we assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. In accordance with SFAS No. 141,Business Combinations, 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

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counterparties and there would be no adjustment to oil and natural gas revenues related to the derivative positions. If, however, the actual sales price is different from the price assumed in the original fair value calculation, the difference would be reflected as either a decrease or increase in oil and natural gas revenues, depending upon whether the sales price was higher or lower, respectively, than the price assumed in the original fair value calculation.

Pursuant to SFAS 133, the change in fair value of the acquired cash flow hedges from the date of acquisition is recorded as a component of accumulated other comprehensive income (loss). In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs. All of these positions were settled as of December 31, 2008.

All derivative financial instruments are recorded on the balance sheet at fair value. The fair value of swaps is generally determined based on the difference between the fixed contract price and the underlying published forward market price. The fair value of collars is determined using an option pricing model which takes into account market volatility, market prices, and contract parameters. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

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,
	2007			2008
Derivative assets (liabilities):
Gas swaps	$	4,709		$	13,312
Oil swaps		(155,782	)		111,416
Gas collars		—			21,682
Oil collars		—			57,716
Natural gas basis differential swaps		539			1,618
	$	(150,534	)	$	205,744

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,
	2006			2007			2008
Reclassification of settled contracts	$	(22,927	)	$	(19,797	)	$	(88,966	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		18,761			(8,343	)		12,549
	$	(4,166	)	$	(28,140	)	$	(76,417	)

During the fourth quarter of 2008, we determined that our natural gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market

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accounting treatment to all outstanding natural gas swaps. The $5,768 cumulative change in fair value attributable to the natural gas swaps that had been accounted for as cash flow hedges and were outstanding as of December 31, 2008 has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income (loss), and the ineffective portion would have been included in the loss from oil and gas hedging activities, which is a component of revenue.

Based upon market prices at December 31, 2008 and assuming no future change in the market, we expect to reclassify $23,537 of the balance in accumulated other comprehensive income to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of December 31, 2008 are expected to be settled by December 2013.

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 gains (losses). All non-hedge derivative contracts outstanding at December 31, 2008 are expected to be settled by December 2013. Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:

	Year ended December 31,
	2006			2007			2008
Change in fair value of non-qualified commodity price swaps	$	(3,746	)	$	(24,416	)	$	9,077
Change in fair value of non-designated costless collars		—			—			79,398
Change in fair value of natural gas basis differential contracts		(846	)		1,385			1,079
Receipts from (payments on) settlement of non-qualified commodity price swaps		—			—			20,290
Receipts from (payments on) settlement of non-designated costless collars		—			—			11,127
Receipts from (payments on) settlement of natural gas basis differential contracts		(85	)		(750	)		5,970
	$	(4,677	)	$	(23,781	)	$	126,941

In December 2008, we early settled oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32,589. Certain swaps that were settled had previously been accounted for as cash flow hedges. The $17,894 cumulative change in fair value attributable to the swaps that had been accounted for as cash flow hedges has been deferred in other comprehensive income (loss), and will be recognized as a gain from oil and gas hedging activities when the hedged production is sold.

Hedge settlement receivables of $51 and $15,315 were included in accounts receivable at December 31, 2007 and 2008, respectively. Hedge settlement payments of $8,759 were included in accounts payable and accrued liabilities at December 31, 2007. There were no hedge settlement payments included in accounts payable and accrued liabilities at December 31, 2008.

We have no Level 1 assets or liabilities as of December 31, 2008. Our derivative contracts classified as Level 2 are valued using quotations provided by price index developers such as Platts and Oil Price Information Service. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

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The fair value hierarchy for our financial assets and liabilities accounted for at fair value on a recurring basis is shown by the following table.

	Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Netting Adjustments(1)			Total Assets (Liabilities) as of December 31, 2008
Derivative assets	$	134,666		$	79,603	$	(5,137	)	$	209,132
Derivative liabilities		(8,525	)		—		5,137			(3,388	)
Total derivative assets (liabilities)	$	126,141		$	79,603	$	—		$	205,744

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31, 2008, were:

Year Ended December 31, 2008	Net Derivative Assets (Liabilities)
Beginning balance	$	172
Total realized and unrealized gains (losses) included in non-hedge derivative gains (losses)		92,250
Purchases, issuances, and settlements		(12,819	)
Ending balance	$	79,603
The amount of total gains (losses) for the period included in non-hedge derivative gains (losses) attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	79,498

Fair value of financial instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2007 and 2008 approximates fair value because substantially all debt carries variable market rates. 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. Based on market prices, at December 31, 2008, the fair value of the 8 ¹/2% Senior Notes and 8 ⁷/8% Senior Notes were $73,125 and $73,125, respectively.

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

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Concentrations of credit risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. We do not require collateral or other security to support the derivative instruments subject to credit risk, however, counterparties to the Company’s derivative instruments are affiliates of its lenders. At December 31, 2008, we had significant commodity derivative net asset balances with the following counterparties:

Counterparty	Fair Value(1)
JP Morgan Chase Bank, N.A.	$	82,378
Calyon Credit Agricole CIB		50,565
The Royal Bank of Scotland plc		48,089
Other		24,712
	$	205,744

(1) The fair value does not include the settlements receivable at December 31, 2008.

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 11.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2006. 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. Sales of oil and natural gas to two purchasers accounted for 23.7% and 10.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2008. 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, 2007 and 2008 is as follows:

	As of December 31,
	2007			2008
Beginning balance	$	28,126		$	30,684
Liabilities incurred in current period		266			707
Liabilities settled in current period		(99	)		(728	)
Accretion expense		2,391			2,712
Ending ARO balance		30,684			33,375
Less current portion		1,000			300
	$	29,684		$	33,075

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Note 6: Long-term debt

Long-term debt consists of the following:

	December 31,
	2007		2008
Revolving credit line with banks	$	447,000	$	594,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 5.50% to 7.283%, due January 2017 through January 2029; collateralized by real property		9,644		15,246
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 4.594% to 9.658%, due January 2009 through October 2012; collateralized by automobiles, machinery and equipment		9,925		14,142
		466,569		623,388
Less current maturities		6,762		5,965
	$	459,807	$	617,423

Maturities of long-term debt as of December 31, 2008 are as follows:

2009	$	5,965
2010		598,472
2011		3,360
2012		1,935
2013		1,044
2014 and thereafter		12,612
	$	623,388

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. The borrowing base, which was redetermined effective December 24, 2008, is $600,000 as of December 31, 2008.

Interest was paid at least every three months during 2007 and 2008. The effective rate of interest on the entire outstanding balance was 7.163% and 5.299% as of December 31, 2007 and 2008, respectively, and was based upon LIBOR. 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, 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

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• 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, 2008.

The Credit Agreement also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to the Company or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Agreement. An acceleration of the Company’s indebtedness under the Credit Agreement could in turn result in an event of default under the indentures for the Company’s Senior Notes, which in turn could result in the acceleration of the Senior Notes.

Our Credit Agreement is scheduled to mature on October 31, 2010. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability, and we may not meet the required Current Ratio, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

Based on our borrowings under our Credit Agreement of $594,000, to meet our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we will be required to achieve Consolidated EBITDAX, as defined in our Credit Agreement, of approximately $240,000 for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters during the year ended December 31, 2009. We had Consolidated EBITDAX of approximately $280,000 for the year ended December 31, 2008. Due to the significant decline in oil and gas prices, we may not generate the required $240,000 of Consolidated EBITDAX in 2009. If we are not able to modify the referenced ratio or otherwise increase Consolidated EBITDAX, such as through the early settlement of additional derivatives, we would not meet the covenants under our Credit Agreement, which, unless waived by our lenders, would constitute an event of default under the Credit Agreement.

If our borrowing base amount is reduced by the banks, or if we expect to be unable to meet our required Current Ratio, or our required Consolidated Senior Total Debt to Consolidated EBITDAX ratio, we could reduce our debt amount by early settling additional derivative contracts, selling nonproducing oil and gas assets, selling non-oil and gas assets, selling producing oil and gas assets, or raising equity. There is no assurance, however, that we will be able to sell our assets or equity at commercially reasonable terms or that any sales would generate enough cash to adequately reduce the borrowing base, or that we will be able to meet our future obligations to the banks.

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, 2008 are as follows:

2009	$	259
2010		223
2011		81
Total minimum lease payments		563
Less amount representing interest		37
Present value of net minimum lease payments		526
Less current portion		235
	$	291

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Note 8: Senior Notes

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.

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.

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

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

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

• make investments;

• create liens on assets;

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

• transfer or sell assets;

• engage in transactions with affiliates;

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

• enter into other lines of business.

In connection with the issuance of the senior notes, the Company capitalized $9,251 of costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized costs of $7,943 and $7,220 as of December 31, 2007 and 2008, respectively, that are included in other assets. Amortization of $598, $660, and $723 was charged to interest expense during the years ended December 31, 2006, 2007 and 2008, respectively, related to these costs.

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;

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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 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. In 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. Total liquidated damages paid in 2008 were $388.

In connection with the issuance of the 8 ⁷/8% senior notes, the Company recorded a discount of $2,671 and capitalized $7,316 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 and $6,386 as of December 31, 2007 and 2008, respectively, 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. Amortization of $185 and $500 was charged to interest expense during the year ended December 31, 2008 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 except for Oklahoma Ethanol, LLC and Chaparral Biofuels, LLC.

Senior Notes at December 31, 2007 and December 31, 2008 consisted of the following:

	December 31,
	2007			2008
8.5% Senior Notes due 2015	$	325,000		$	325,000
8.875% Senior Notes due 2017		325,000			325,000
Discount on Senior Notes		(2,510	)		(2,325	)
	$	647,490		$	647,675

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Note 9: Income taxes

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

	2006			2007			2008
Current tax benefit
Federal tax benefit	$	(6	)	$	(8	)	$	(22	)
State tax benefit		(16	)		(8	)		(6	)
Current tax benefit		(22	)		(16	)		(28	)
Deferred tax expense (benefit)
Federal tax expense (benefit)		13,285			(2,349	)		(29,575	)
State tax expense (benefit)		1,554			(380	)		(4,783	)
Deferred tax expense (benefit)		14,839			(2,729	)		(34,358	)
	$	14,817		$	(2,745	)	$	(34,386	)

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:

	2006		2007		2008
Statutory rate	35.0	%	35.0	%	35.0	%
State income taxes, net of federal benefit	3.6	%	3.6	%	3.6	%
Statutory depletion	(0.5	)%	(0.5	)%	(0.5	)%
Other	0.3	%	(1.7	)%	0.5	%
Effective tax rate	38.4	%	36.4	%	38.6	%

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

	2007			2008
Deferred tax assets related to
Derivative instruments	$	48,691		$	—
Inventories		—			49
Asset retirement obligations		2,981			3,837
Accrued expenses, allowance and other		2,346			1,442
Net operating loss carryforwards
Federal		30,771			81,431
State		12,657			15,403
Statutory depletion carryforwards		1,434			1,516
Alternative minimum tax credit carryforwards		204			308
		99,084			103,986
Less: valuation allowance		7,999			5,848
Deferred tax asset		91,085			98,138
Deferred tax liabilities related to
Derivative instruments		—			(79,582	)
Property and equipment		(88,865	)		(80,951	)
Inventories		(588	)		—
Deferred tax liability		(89,453	)		(160,533	)
Net deferred tax asset (liability)		1,632			(62,395	)
Less net current deferred tax asset (liability)		19,128			(19,696	)
Long-term deferred tax asset (liability)	$	(17,496	)	$	(42,699	)

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Approximately $18,736 and $(19,886) of the current deferred tax asset (liability) at December 31, 2007 and 2008, respectively, relates to the short-term derivative instruments. Additionally, approximately $387 and $131 of the current deferred tax asset (liability) relates to asset retirement obligations at December 31, 2007 and 2008, respectively. At December 31, 2007 and 2008, taxes receivable of $74 and $85, respectively, are included in accounts receivable.

The Company has federal net operating loss carryforwards of approximately $232,700 at December 31, 2008, which will begin to expire in 2009 if unused, of which significant amounts begin to expire in 2018. At December 31, 2008, the Company has state net operating loss carryforwards of approximately $272,000, which will begin to expire in 2009. At December 31, 2008, approximately $103,000 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. The decrease in the valuation allowance of $2,151 for 2008 relates to adjustments to expected realization of state net operating loss carryforwards. In addition, at December 31, 2008, the Company had tax percentage depletion carryforwards of approximately $4,332 which are not subject to expiration.

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. All significant intercompany balances and transactions are eliminated in consolidation.

The service company was acquired during the second quarter of 2007, therefore, no segment information is provided for the year ended December 31, 2006.

	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
For the Year Ended December 31, 2008:
Revenues	$	425,344		$	72,852		$	(38,580	)	$	459,616
Intersegment revenues		—			(38,580	)		38,580			—
Total revenues		425,344			34,272			—			459,616
Income (loss) before income taxes	$	(92,114	)	$	5,609			(2,631	)	$	(89,136	)
As of December 31, 2008:
Total assets	$	1,712,891		$	38,789		$	(38,844	)	$	1,712,836

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

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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, now CHK Holdings, L.L.C., (“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; $8,028 and $4,107, respectively, for the year ended December 31, 2007; and $9,033 and $3,764, respectively, for the year ended December 31, 2008 on these properties. In addition, Chesapeake participates in ownership of properties operated by the Company. The Company paid revenues and recorded joint interest billings to Chesapeake of: $1,809 and $2,556, respectively, for the year ended December 31, 2006; $1,409 and $1,552, respectively, for the year ended December 31, 2007; and $2,941 and $3,007, respectively, for the year ended December 31, 2008. Amounts receivable from and payable to Chesapeake were $1,300 and $515, respectively, as of December 31, 2007. Amounts receivable from and payable to Chesapeake were $1,914 and $1,188, respectively, as of December 31, 2008.

Note 12: Deferred compensation

Effective January 1, 2004, the Company implemented a Phantom Unit Plan, which was revised on January 1, 2007 as the First Amended and Restated Phantom Stock Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to participants in total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom stock available for award. Under the current plan, awards vest on the fifth anniversary of the award date, 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 stock will vest if a change of control event occurs. Upon vesting, participants are entitled to redeem their phantom stock for cash within 120 days of the vesting date.

Effective with the First Amended and Restated Phantom Stock Plan, the vesting period was reduced from the seventh anniversary of the award date to the fifth anniversary of the original award date. In accordance with SFAS No. 123(R),Share Based Payments (“SFAS 123(R)”), 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 $280, net of $137 capitalized, during the year ended December 31, 2007 as a result of the modification.

Prior to January 1, 2006, the Company accounted for its deferred compensation plan under the recognition and measurement provisions of APB Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations, which requires that the award be measured at the end of each period based on the current calculated fair value of the award. Effective January 1, 2006, the Company adopted the fair value recognition provisions of SFAS 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 123(R). Since the phantom stock is a liability award, fair value of the stock 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 stock in cash within 120 days of the vesting date. Results for prior periods have not been restated and the Company had no cumulative effect adjustment upon adoption of SFAS 123(R) under the modified-prospective method.

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.

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Compensation expense is recognized over the vesting period of the phantom stock 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. Due to a reduction in the fair value of the phantom stock during 2008, the Company recognized a deferred compensation gain during the year ended December 31, 2008. The Company recognized deferred compensation expense (gain) as follows for the years ended December 31:

	2006			2007			2008
Deferred compensation cost (gain)	$	128		$	1,246		$	(466	)
Less: deferred compensation cost capitalized		(44	)		(415	)		160
Deferred compensation expense (gain)	$	84			831			(306	)

A summary of the Company’s phantom stock activity for the years ended December 31, 2006, 2007, and 2008 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 January 1, 2006	$	17.89	164,906
Granted	$	14.29	21,357
Vested	$	14.29	(52	)
Forfeited	$	14.29	(26,173	)
Unvested and total outstanding at December 31, 2006	$	14.29	160,038		4.66	$	2,287
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
Granted	$	10.22	31,158
Vested	$	10.22	—
Forfeited	$	10.22	(12,343	)
Unvested and total outstanding at December 31, 2008	$	10.22	219,658		1.49	$	2,245

There are no vested units as of December 31, 2008. As of December 31, 2008, there was approximately $694 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 1.49 years. Deferred compensation cost of $789 that will vest within the next twelve months was included in accrued payroll and benefits payable as of December 31, 2008. There was no deferred compensation cost included in accrued payroll and benefits payable as of December 31, 2007, as there were no shares vesting within the next twelve months.

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, 2006, 2007 and 2008, there were 415, 613 and 691 employees, respectively, participating in the plan. Contributions recognized by the Company totaled $883, $1,720 and $1,883 for the years ended December 31, 2006, 2007 and 2008, respectively.

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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, and with utilities for liabilities relating to operation of CO₂ compression equipment. We had various Letters outstanding totaling $865, $1,690, and $2,730 as of December 31, 2006, 2007, and 2008, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 7.163% at December 31, 2007 and 5.299% at December 31, 2008) for all amounts paid by the lenders under the Letters. We paid no interest on the Letters during 2006, 2007, or 2008.

We have 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, 2006, 2007, and 2008 was $3,506, $6,766, and $7,116, respectively.

We have open purchase orders for inventory totaling $1,685 at December 31, 2008.

We have long-term contracts to purchase up to all of the CO₂ manufactured at two existing ethanol plants. Based on plant capacity, it is estimated that we will purchase an average of approximately 4.2 MMcf per day over the ten-year contract term, which will begin upon our first purchase, under one contract, and under the second contract an average of approximately 13.75 MMcf per day over the fifteen-year contract term, which begins in 2009. Pricing under both contracts is variable over time and both contracts have the possibility of renewal. We have rights under two additional 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. We have historically taken less CO₂ than the maximum allowed in the contract and based on our current level, we project we would purchase an average of approximately 16.0 MMcf per day over the remainder of the initial term of the contract, which expires in 2011. The contract automatically renews for an additional ten years unless terminated by us. We may also purchase a variable amount of CO₂ under the second contract and we are currently purchasing an average of approximately 5.0 MMcf per day and project our purchases to remain at that level through 2009. The contract expires in 2016. We may terminate this contract at the end of any calendar year with 13 months notice. Pricing under both contracts is dependent on certain variable factors, including the price of oil.

During 2007 the Company entered into change of control severance agreements under 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, we recorded a receivable 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 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 the John Milton Graves Trust u/t/a 6/11/2004 , et al, seeking a declaratory judgment confirming this position, and amended our petition on December 1, 2008 to clarify that we are also seeking recovery of the purchase price adjustment amount under a breach of contract theory. The sellers responded by filing a counter claim seeking approximately $4,378 related to an election under the federal tax code. Discovery in the lawsuit is proceeding, and mediation is scheduled in the second quarter of 2009. As of December 31, 2007 and 2008, the recorded receivable was $14,406 and was included in other assets on the consolidated balance sheet. As of December 31, 2007 and 2008, the recorded

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payable related to the election under the tax code was $4,378 and was included in accounts payable and accrued liabilities on the consolidated balance sheet.

In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. We currently estimate that the total costs attributable to the loss of well control will be approximately $12,455. We anticipate our insurance policy will cover 100% of these costs up to a maximum of $35,000, with the $627 insurance retention and deductible being payable by us. As of December 31, 2008, we received $8,111 for costs incurred through August 9, 2008, and recorded the insurance proceeds as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows. We have submitted to our insurer additional claims totaling approximately $3,717 for costs incurred through August 9, 2008.

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 for an aggregate cash purchase price of $102,000. Proceeds from the sale after commissions and expenses were approximately $100,900 and were used for general corporate and working capital purposes and acquisitions of oil and gas properties.

Cash dividends of $1,049 were paid during the year ended December 31, 2006. Dividends of $350 were paid on a quarterly basis from January 1, 2005 through September 30, 2006.

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:

	2006		2007		2008
Property acquisition costs
Proved properties(1)	$	484,404	$	41,724	$	39,201
Unproved properties		4,731		8,032		6,677
Total acquisition costs		489,135		49,756		45,878
Development costs(2)		170,987		165,177		251,690
Exploration costs		7,015		15,287		5,108
Total	$	667,137	$	230,220	$	302,676

(1) Includes $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.

(2) Includes $16,090 of costs related to the construction of a compressor station and CO₂ pipeline in 2008.

The average depreciation, depletion and amortization rate per equivalent unit of production (Mcfe) was $1.45, $1.94 and $2.15 for the years ended December 31, 2006, 2007 and 2008, respectively.

Oil and gas properties not subject to amortization consist of the cost of unevaluated leaseholds, seismic costs associated with specific unevaluated properties and wells in progress. Of the $16,865 of unproved property costs at December 31, 2008 being excluded from the amortization base, $2,599, $4,583 and $5,267 were incurred in 2006, 2007 and 2008, respectively, and $4,416 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.

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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., Ryder Scott Company, L.P., and Lee Keeling & 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 (“SFAS 69”). Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time.

The Company’s oil and gas reserves are attributable solely to properties within the United States. A summary of the Company’s changes in quantities of proved oil and gas reserves for the years ended December 31, 2006, 2007 and 2008 are as follows:

	Oil (Mbbls)		Gas (MMcf)		Total (Mmcfe)
Balance at January 1, 2006	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
Purchase of minerals in place	1,170		7,549		14,569
Sales of minerals in place	(31	)	(854	)	(1,040	)
Extensions and discoveries	2,444		51,149		65,813
Revisions(2)	(46,784	)	(67,414	)	(348,118	)
Improved recoveries	(847	)	9,462		4,380
Production	(3,773	)	(19,795	)	(42,433	)
Balance at December 31, 2008	51,283		372,366		680,064
Proved developed reserves:
December 31, 2006	57,824		281,958		628,902
December 31, 2007	61,567		269,578		638,980
December 31, 2008	40,382		263,331		505,623

(1) The downward revision in our gas reserves during 2006 was primarily due to a decrease in price from $10.08 as of December 31, 2005 to $5.64 as of December 31, 2006 and an overall increase in lifting costs.

(2) The downward revision in our oil and gas reserves during 2008 was primarily due to a decrease in price from $96.01 and $6.80, respectively, as of December 31, 2007 to $44.60 and $5.62, respectively as of December 31, 2008.

The following information was developed using procedures prescribed by SFAS 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.

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

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

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

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

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

Under the standardized measure, future cash inflows were estimated by applying year-end oil and gas prices, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 4, “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 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:

	2006			2007			2008
Future cash flows	$	7,239,850		$	11,718,944		$	4,198,416
Future production costs		(3,144,707	)		(4,600,663	)		(1,841,786	)
Future development and abandonment costs		(577,123	)		(914,561	)		(438,360	)
Future income tax provisions		(953,794	)		(2,017,915	)		(338,416	)
Net future cash flows		2,564,226			4,185,805			1,579,854
Less effect of 10% discount factor		(1,482,017	)		(2,391,825	)		(824,841	)
Standardized measure of discounted future net cash flows	$	1,082,209		$	1,793,980		$	755,013

Future cash flows as shown above were reported without consideration for the effects of hedging transactions outstanding at each period end. Based on year-end spot prices used in determining future net revenues, if the effects of hedging transactions were included in the computation, then future cash flows would have increased (decreased) by $61,226, ($177,019), and $259,793 in 2006, 2007 and 2008, 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:

	2006			2007			2008
Beginning of year	$	1,067,888		$	1,082,209		$	1,793,980
Sale of oil and gas produced, net of production costs		(158,361	)		(235,273	)		(347,749	)
Net changes in prices and production costs		(472,700	)		918,714			(1,184,385	)
Extensions and discoveries		52,366			275,720			231,614
Improved recoveries		6,538			162,841			15,415
Changes in future development costs		27,917			(138,791	)		142,143
Development costs incurred during the period that reduced future development costs		30,989			4,978			181,462
Revisions of previous quantity estimates		(137,268	)		(83,894	)		(1,225,090	)
Purchases and sales of reserves in place, net		408,000			44,869			46,148
Accretion of discount		161,752			149,406			401,154
Net change in income taxes		140,413			(462,311	)		703,123
Changes in production rates and other		(45,325	)		75,512			(2,802	)
End of year	$	1,082,209		$	1,793,980		$	755,013

Average prices in effect at December 31, 2006, 2007 and 2008 used in determining future net revenues related to the standardized measure calculation are as follows:

	2006		2007		2008
Oil (per Bbl)	$	61.06	$	96.01	$	44.60
Gas (per Mcf)	$	5.64	$	6.80	$	5.62

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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 us, including our 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, 2008, 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 relating to and the 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 our receipts and expenditures 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 inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework inInternal Control—Integrated Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2008.

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This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us 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, 2008 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	59	Chairman, Chief Executive Officer and President
Joseph O. Evans	54	Chief Financial Officer and Executive Vice President and Director
Robert W. Kelly II	51	Senior Vice President and General Counsel
Larry E. Gateley	59	Senior Vice President—Reservoir Engineering and Acquisitions
James M. Miller	46	Senior Vice President—Operations and Production Engineering
Charles A. Fischer, Jr.	60	Director

Mark A. Fischer, Chairman, Chief Executive Officer, President and Co-Founder, co-founded the Company 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 with an Honors degree in Aerospace Engineering, and currently serves on the Engineering Advisory Council for Texas A&M University. Mark A. Fischer and Charles A. Fischer, Jr. are brothers.

Joseph O. Evans, Chief Financial Officer & Executive Vice President & Director, joined the Company 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 SEC 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 the Company in 2001 and oversees the legal, land, marketing and environmental functions. Prior to joining the Company, 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, and a Juris Doctor from the Oklahoma City University School of Law.

Larry E. Gateley, Sr. Vice President—Reservoir Engineering and Acquisitions, joined the Company in 1997 as the Reservoir Engineering and Acquisitions Manager, and is responsible for the Company Reservoir Group,

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which prepares the Company Annual Reserve Report, the Acquisition Department, the Company EOR Special Projects Group, and the Joint Interests Department. Mr. Gateley has 33 years of diversified management and operational and technical engineering experience. His previous positions include Reservoir/Production/Drilling Engineer for Exxon Company USA, Sr. Petroleum Engineer for J.M. Huber Corp., Chief Drilling Engineer for Post Petroleum Inc., Vice President and Co-Owner of Wood-Gate Engineering Inc., Vice President of Acquisitions for SMR Energy Income Funds, and Acquisitions Manager for Frontier Natural Gas Corporation. Mr. Gateley is a registered Professional Engineer in the states of Oklahoma and Texas. He is a graduate of the University of Oklahoma with a Bachelor of Science degree in Mechanical Engineering.

James M. Miller, Sr. Vice President—Operations & Production Engineering, joined the Company in 1996, as Operations Engineer. Since joining the Company, 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.

Charles A. Fischer, Jr., Director and Co-Founder, co-founded the Company in 1988, and has served as a director of the Company since its inception. Mr. Fischer served as the Company’s Chief Administrative Officer and Executive Vice President from July 2005 until his retirement effective July 27, 2007. Mr. Fischer joined the Company 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 six years, and received the 2001 Industry Achievement Award. He graduated from Texas A&M University with a Bachelor of Science degree in Biology and from the University of Wisconsin with a Master of Science degree in Ecology.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that is applicable to all employees, officers and members of our board of directors. The Code of Business Conduct and Ethics is available on our website at www.chaparralenergy.com.

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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 our 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 our 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 (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 119 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 our overall 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

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

For 2008, Senior Executive base salaries were targeted at or around the 50^th percentile of base salaries of similarly sized companies within the Benchmark Group and Survey Data. Base salaries are determined by evaluating a Senior Executive’s level of responsibility and experience and our performance.

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

In setting the base salary of the Senior Executives for fiscal year 2008, 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 2008 are shown in the Summary Compensation Table in this annual report.

Annual Officers Bonus

We established the Annual Officers Bonus program in September 2006. The Annual Officers Bonus provides Senior Executives with the opportunity to earn cash bonuses based on our achievement of unspecified Company-wide goals as determined by the PEO. The bonus is a component of the compensation program designed to align Senior Executive pay with our annual (short-term) performance.

The 2008 Annual Officers Bonus was 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 Annual Officers Bonuses awarded to the PEO and the NEO’s are shown in the Summary Compensation Table. The 2008 Annual Officers Bonuses were awarded in March 2009.

Phantom Plan

The First Amended and Restated Phantom Stock Plan (“Phantom Plan”) is a deferred compensation plan. The objective of the Phantom Plan is to provide Senior Executives who are not stockholders, Executive Employees 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.

The term “phantom stock” refers to units of value that trace our fair market value, as defined by the Phantom Plan. The phantom stock is not convertible into stock and does not possess any voting rights. Phantom stock will be exchanged for cash upon vesting. Phantom stock may be awarded in total up to 2% of our fair market value, as defined by the Phantom Plan. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom stock available for award. Generally, phantom stock vests on the fifth anniversary of the award date of the phantom stock, 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 the Company without cause.

Also, phantom stock vests if a change of control event occurs. A change of control event will occur under the Phantom Plan if (1) our stockholders as of January 1, 2004, the date of the creation of the Phantom Plan, collectively sell a majority of their shares (either publicly or privately) to a person who is not majority owned by them collectively, and in the process lose operational control of us (i.e., the position of President, Chief Executive Officer or Chairman of us or our subsidiary Chaparral Energy, L.L.C. is not held by either Mark A. Fischer or Charles A. Fischer, Jr.), (2) the termination, liquidation or dissolution of us or Chaparral Energy L.L.C. 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.

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The Phantom Plan was effective January 1, 2004 and was amended and restated effective January 1, 2007. At the creation of the Phantom 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 we exceed or do not meet those growth rates. We believe that this aligns the Senior Executives’ compensation to stockholder value by providing a proprietary interest in our value. Although no adjustments were made for 2008, the predetermined subsequent annual awards can be adjusted to recognize exemplary performance or increased responsibility consistent with the philosophy of relating individual compensation to performance.

Non-Equity Incentive in Lieu of Phantom Plan Awards or Restricted Stock Awards

In September 2006, concurrent with the creation of the Annual Officers Bonus, we ceased to grant phantom units to our Officers under the Phantom Plan. In anticipation of the consummation of an initial public offering, which we were preparing for at that time, our board planned to approve grants of restricted stock to our Officers following consummation of our initial public offering. Because the initial public offering was not consummated, our board approved the payment of cash to our Officers in lieu of making grants of restricted stock in a private entity.

In 2008, we expected to become a publicly traded company following the consummation of a merger with Edge Petroleum Corporation. Based on such expectations, our board planned to approve grants of restricted stock to our Officers following consummation of the merger. Because the merger was never consummated, our board approved the payment of cash to our Officers in lieu of making grants of restricted stock in a private entity.

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 we may deduct in any year with respect to the PEO and the NEO’s 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 our stockholders. We may from time to-time-pay compensation to our Senior Executives that may not be deductible, including discretionary bonuses or other types of compensation outside of our plans, such as recruitment, when it is consistent with our overall philosophy.

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

Although we may deduct equity awards for tax purposes, 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, we 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. The medical credit is being

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phased out. Effective January 1, 2009, no credit is being offered to any newly hired employee, and on June 30, 2009, all medical credits will be eliminated.

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

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

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

Effective January 1, 2009, contributions will vest as follows:

Years of Service for Vesting	Percentage
1	33	%
2	33	%
3	34	%

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 our 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.

Indemnification agreements

We have indemnification agreements with Mark A. Fischer, Charles A. Fischer, Jr., Joseph O. Evans and Robert W. Kelly II. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of 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 capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements will generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements will also obligate us to promptly advance all reasonable expenses incurred in connection with any

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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 also maintain director and officer liability insurance for the benefit of each of the above indemnities. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnities are 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.

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.

Mark A. Fischer

Joseph O. Evans

Charles A. Fischer

Compensation Committee Interlocks and Inside Participation

None of our executive officers have served as members of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors. We do not have a compensation committee. Two of the members of our board of directors are also executive officers and participated in deliberations concerning current executive officer compensation.

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2008 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, 2007, and 2008.

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards ($)(4)		Option Awards ($)	Non-Equity Incentive Plan Compensation ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)			Total ($)
Mark A. Fischer,	2008	$	531,115	224,180	(1)	—		—	224,180	(5)	—	$	34,176	(7)	$	1,013,651
Chief Executive Officer and President	2007 2006		457,539 351,258	400,000 245,165	(2) (3)	—   —		—   —	400,000 —	(6)	—   —		24,964 22,363	(7) (7)		1,282,503 618,786
Joseph O. Evans,	2008		301,115	107,437	(1)	(4,170	)	—	107,437	(5)	—		21,960	(7)		537,949
Chief Financial Officer and Executive Vice President	2007 2006		264,193 227,285	192,000 90,369	(2) (3)	15,734 11,895		—   —	192,000 —	(6)	—   —		16,693 13,719	(7) (7)		680,620 343,268
Larry E. Gateley,	2008		252,462	80,690	(1)	(61,613	)	—	80,690	(5)	—		22,831	(7)		436,673
Senior Vice President—Reservoir Engineering and Acquisitions	2007 2006		222,654 189,362	144,000 72,727	(2) (3)	100,440 74,774		—   —	144,000 —	(6)	—   —		16,573 11,530	(7) (7)		627,667 348,393
James M. Miller,	2008		239,000	76,595	(1)	(61,613	)	—	76,595	(5)	—		16,274	(8)		408,464
Senior Vice President— Operations and Production Engineering	2007 2006		211,346 170,885	137,000 67,463	(2) (3)	100,440 74,774		—   —	137,000 —	(6)	—   —		149,899 99,514	(8) (8)		735,685 412,636
Robert W. Kelly II,	2008		239,000	76,595	(1)	(61,613	)	—	76,595	(5)	—		18,777	(7)		410,967
Senior Vice President and General Counsel	2007 2006		211,346 178,777	137,000 68,923	(2) (3)	100,440 74,774		—   —	137,000 —	(6)	—   —		13,275 8,462	(7) (7)		599,061 330,936

(1) Paid on March 15, 2009.

(2) Paid on April 2, 2008.

(3) Includes amounts paid under the profit sharing and retention bonus plans and amounts earned under the 2006 Annual Officers Bonus that were paid on April 2, 2007. The amounts of unpaid Annual Officers Bonuses at December 31, 2006 were $105,233, $45,817, $32,851, $31,996, and $31,365 for Messrs. Mark A. Fischer, Joseph O. Evans, Larry E. Gateley, James M. Miller, and Robert W. Kelly II, respectively.

(4) The values shown are the amounts recognized in our financial statements in accordance with SFAS 123(R) for the changes in the fair value and amortization of the phantom stock awards granted in 2004, 2005, and 2006, excluding the impact of estimated forfeitures related to service-based vesting conditions. The 2008 amounts reflect the reduction in the fair value of the phantom stock. This resulted in a negative aggregate number for our NEOs for 2008; these negative numbers have not been included in the “Total” column of this table. See Note 12 to our consolidated financial statements for the valuation assumptions made.

(5) Paid on January 7, 2009.

(6) Paid on January 2, 2008.

(7) Includes: for Mark A. Fischer $10,128, $17,339 and $20,500 in matching 401(k) contributions, $8,400, $3,050, and $1,300 for the use of a Company vehicle, and $891, $1,631, and $6,091 for the use of the Company airplane; for Joseph O. Evans $13,282, $16,257 and $20,500 in matching 401(k) contributions; for Larry E. Gateley $10,822, $15,866 and $20,500 in matching 401(k) contributions; for Robert W. Kelly II $8,227, $13,040 and $17,591 in matching 401(k) contributions in 2006, 2007 and 2008, respectively.

(8) Includes $10,318, $14,525 and $15,500 in matching 401(k) contributions in 2006, 2007, and 2008, respectively, 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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2008 GRANTS OF PLAN-BASED AWARDS TABLE

There were no awards of any plan-based awards to any NEO during 2008.

2008 OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END TABLE

The following table shows outstanding phantom unit awards as of December 31, 2008 for each NEO that participates in the Phantom Plan.

	Stock Awards
Name	Number of Shares of Stock That Have Not Vested(1) (#)	Market Value of Shares or Units of Stock That Have Not Vested(2) ($)
Joseph O. Evans	3,974	$	40,614
Larry E. Gateley	21,894		223,757
James M. Miller	21,894		223,757
Robert W. Kelly II	21,894		223,757

(1) For Joseph O. Evans, phantom stock vests as follows: 3,554 stock units on July 1, 2010 and 420 stock units on January 1, 2011; for Larry E. Gateley, Robert W. Kelly II and James M. Miller, phantom stock vests as follows: 19,306 stock units on January 1, 2009; 1,749 stock units on January 1, 2010; and 839 stock units on January 1, 2011. Payments for Larry E. Gateley, Robert W. Kelly II and James M. Miller will be made of approximately $197,307 for the vested stock in 2009.

(2) The table assumes a market value of $10.22 at December 31, 2008 which is calculated in accordance with the provisions of the Phantom 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 in Control Severance Agreements

Each of our NEO’s is party to a change in 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 the 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 our voting securities, (2) a merger of the Company, or (3) the sale or disposition of all or substantially all of our assets; 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 our voting securities prior to such transaction beneficially own more than 50% of our common stock 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, 2008.

Name	Base Salary		Target Bonus		Multiplier	Benefits		Total
Mark A. Fischer	$	547,000	$	448,360	3	$	35,901	$	3,021,981
Joseph O. Evans		310,000		214,874	2.5		34,351		1,346,536
Larry E. Gateley		260,000		161,380	2		34,020		876,780
James M. Miller		246,000		153,190	2		28,924		827,304
Robert W. Kelly II		246,000		153,190	2		27,047		825,427

Phantom Stock Plan Awards

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

If a change of control as defined in the Phantom Stock 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 us or a successor company.

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Under the Phantom 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 Plan, collectively sell a majority of their Membership Units (either publicly or privately) to a party which is not majority owned by them collectively, and 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 Charles A. Fischer, Jr.); or

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

• We sell substantially all of our assets.

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

Phantom stock awards vest on a pro-rata basis on the January 1 or July 1 which immediately follows the participant’s 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 from the award date to the date of vesting (to a maximum of five years) by five and then multiplying the number of phantom shares in the award by the result. Phantom shares which do not vest hereunder will be forfeited to us 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 Board, such participant is subject to a physical or mental condition which renders or is expected to render the participant unable to perform his or her usual duties. A participant is considered retired if the participant’s full-time employment with us terminates at or after the date the participant attains the age of 65 years.

The table below quantifies the value of the accelerated vesting of the phantom units owned by each of our NEO’s assuming we underwent a change of control on December 31, 2008 or that on December 31, 2008, we terminated each NEO without cause or their employment was terminated by reason of death, disability, or retirement.

Name	Change of Control		Death, Disability, Retirement, or Termination Without Cause
Joseph O. Evans	$	40,614	$	28,001
Larry E. Gateley		223,757		216,752
James M. Miller		223,757		216,752
Robert W. Kelly II		223,757		216,752

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 receive amounts earned during his term of employment, including unused vacation pay and bonuses earned but not yet paid under the Annual Officers Bonus. The amounts of the unpaid Annual Officers Bonuses at December 31, 2008 were $224,180, $107,437, $80,690, $76,595 and $76,595 for Messrs. Mark A. Fischer, Joseph O. Evans, Larry E. Gateley, James M. Miller, and Robert W. Kelly II, respectively.

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

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

Principal Stockholders

The following table sets forth information, as of March 30, 2009, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, and each of the five most highly compensated executive officers, and by all directors and executive officers as a group.

	Beneficial ownership
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.

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

Transactions with Related Persons, Promoters and Certain Control Persons

Participation Interests

Historically, we have granted participation interests in the form of overriding royalty interests to a limited number of employees. We have also granted pro rata certain overriding royalty interests to our 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 $939,072 in 2008. Payments on these interests to Mark A. Fischer were $117,242 in 2008. Payments on these interests to Charles A. Fischer, Jr. were $30,104 in 2008. Payments on these interests to James M. Miller were $261,420 in 2008.

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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 acquired a 31.9% beneficial interest in the Company through the sale of common stock. We participate in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings of $9,033,000 and $3,764,000, respectively for the year ended December 31, 2008 on these properties. In addition, Chesapeake participates in ownership of properties operated by us. During the year ended December 31, 2008, we paid revenues and recorded joint interest billings of $2,941,000 and $3,007,000, respectively to Chesapeake. Amounts receivable from and payable to Chesapeake were $1,914,000 and $1,188,000, respectively as of December 31, 2008.

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 (“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 us. A “Qualified Initial Public Offering” is defined as (i) a consummated initial public offering of shares of common stock of Chaparral, which is underwritten on a firm commitment basis by a nationally-recognized investment banking firm, or (ii) any transaction resulting in the initial listing or quotation of the shares of common stock on a national securities exchange or on the Nasdaq National Market. As long as the Selling Stockholders and their permitted transferees continue to own in the aggregate in excess of 50% of our outstanding shares of common stock, Fischer will have the power to nominate and elect two directors to our 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 our outstanding shares of common stock) will have the power to nominate and elect one director to our 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 our outstanding shares of common stock) has the power to nominate and elect one director to our 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 our certificate of incorporation, (iii) the sale of all or substantially all of our assets, or (iv) a termination of our business, unless Fischer votes for such approval.

Preemptive Rights; Standstill. Subject to the procedures set forth in the Stockholders’ Agreement, if we propose to sell any of our 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 our equity securities 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 our board of directors, acquire or publicly announce any intention to acquire shares of our common stock 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 our common stock.

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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 until (i) such time that Fischer and its affiliates own less than 25% of the shares of our 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 our common stock 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 our common stock, 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, we agree to use our 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 us up to the number of shares being sold by us in such offering, but not to exceed $100 million without the consent of Altoma. If our 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 us, and then to Chesapeake and Fischer, in accordance with the procedures set forth in the Stockholders’ Agreement.

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

Registration Rights; Piggyback Registration. At any time after a Qualified Initial Public Offering, Fischer, Altoma and Chesapeake will have demand rights to require us to register shares of our common stock. Fischer may on up to four occasions, and Altoma and Chesapeake may on up to two occasions each, require us 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 we are 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 us 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

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company controlled by Mark A. Fischer 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 us 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 but we have no written policy in place at this time.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Independent Auditor and Fees

Grant Thornton LLP, our independent registered public accounting firm, audited our consolidated financial statements for fiscal 2008. Grant Thornton LLP has billed us and our subsidiaries fees as set forth in the table below for (i) the audits of our 2007 and 2008 annual financial statements, reviews of quarterly financial statements, and review of our filings on Form 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 our financial statements, and (iii) services related to tax compliance.

	Audit Fees		Audit- Related Fees		Tax Fees(1)
Fiscal 2008(2)	$	397,686	$	24,411	$	21,825
Fiscal 2007(2)	$	414,711	$	4,036	$	21,160

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

(2) There were no fees billed in 2007 or 2008 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 2008 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
2.1*	Agreement and Plan of Merger among the Company, Chaparral Exploration, L.L.C. and Edge Petroleum Corporation, dated July 14, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on July 15, 2008)
2.2*	Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C., and Edge Petroleum Corporation (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on December 17, 2008)
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)
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)

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Exhibit No.	Description
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)
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 4.6). (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*†	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)
10.3*†	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)
10.4*†	Phantom Unit Plan (Incorporated by reference to Exhibit 10.8 to Form S-1 (SEC File No. 333-130749), filed on February 14, 2006)
10.5*†	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)
10.6*	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)
10.7*	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)
10.8*	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)
10.9*	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
10.10*	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)
10.11*	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)
10.12*	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)
10.13*	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)
10.14*†	First Amended and Restated Phantom Stock Plan dated January 1, 2007 (Incorporated by reference to Exhibit 10.7 of the Company’s Quarterly Report on Form 10-Q, filed on August 14, 2008)
10.15*	Stock Purchase Agreement, dated as of July 14, 2008, by and between the Company and Magnetar Financial LLC (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on July 15, 2008)
10.16*	Termination and Settlement Agreement, dated December 16, 2008, among Chaparral Energy, Inc., on behalf of itself and Chaparral Exploration, L.L.C., Edge Petroleum Corporation and Magnetar Financial LLC, on behalf of itself and its affiliates (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on December 17, 2008)
10.17*†	Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof (Incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K (SEC File No. 333-134748), filed on March 31, 2008)
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, 2009

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, 2009
/s/    JOSEPH O. EVANS         Joseph O. Evans	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer) and Director	March 31, 2009
/s/    CHARLES A. FISCHER, JR.         Charles A. Fischer, Jr.	Director	March 31, 2009

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EXHIBIT INDEX

Exhibit No.	Description
2.1*	Agreement and Plan of Merger among the Company, Chaparral Exploration, L.L.C. and Edge Petroleum Corporation, dated July 14, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on July 15, 2008)
2.2*	Merger Termination Agreement, dated December 16, 2008, among Chaparral Energy, Inc., Chaparral Exploration, L.L.C., and Edge Petroleum Corporation (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on December 17, 2008)
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)
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)
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 4.6). (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)

Exhibit No.	Description
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*†	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)
10.3*†	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)
10.4*†	Phantom Unit Plan (Incorporated by reference to Exhibit 10.8 to Form S-1 (SEC File No. 333-130749), filed on February 14, 2006)
10.5*†	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)
10.6*	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)
10.7*	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)
10.8*	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)
10.9*	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)
10.10*	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)
10.11*	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)
10.12*	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)
10.13*	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)
10.14*†	First Amended and Restated Phantom Stock Plan dated January 1, 2007 (Incorporated by reference to Exhibit 10.7 of the Company’s Quarterly Report on Form 10-Q, filed on August 14, 2008)

Exhibit No.	Description
10.15*	Stock Purchase Agreement, dated as of July 14, 2008, by and between the Company and Magnetar Financial LLC (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on July 15, 2008)
10.16*	Termination and Settlement Agreement, dated December 16, 2008, among Chaparral Energy, Inc., on behalf of itself and Chaparral Exploration, L.L.C., Edge Petroleum Corporation and Magnetar Financial LLC, on behalf of itself and its affiliates (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on December 17, 2008)
10.17*†	Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof (Incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K (SEC File No. 333-134748), filed on March 31, 2008)
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