Chaparral Energy (CHAP) 10-Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 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 number: 333-153049

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)

(405) 478-8770

(Registrant’s telephone number, including area code)

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a small 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

877,000 shares of the registrant’s Common Stock were outstanding as of November 13, 2008.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of December 31, 2007 and September 30, 2008 (Unaudited)	4
Consolidated Statements of Operations for the three months and nine months ended September  30, 2007 and 2008 (Unaudited)	5
Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2008 (Unaudited)	6
Notes to Consolidated Financial Statements (Unaudited)	8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Overview	19
Results of Operations	21
Liquidity and Capital Resources	26
Critical Accounting Policies and Estimates	30
Recent Accounting Pronouncements	32
Item 3. Quantitative and Qualitative Disclosures About Market Risk	32
Item 4. Controls and Procedures	34
Part II. OTHER INFORMATION	35
Item 1. Legal Proceedings	35
Item 1A. Risk Factors	35
Item 4. Submission of Matters to a Vote of Security Holders	36
Item 6. Exhibits	36
Signatures	37
EX-31.1 (Certification by CEO required by rule 13a-14(a)/15d-14(a))
EX-31.2 (Certification by CFO required by rule 13a-14(a)/15d-14(a))
EX-32.1 (Certification by CEO pursuant to section 906)
EX-32.2 (Certification by CFO pursuant to section 906)

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 OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this report:

• Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil, condensate, or natural gas liquids.

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

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

• 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.

• MMcf. One million cubic feet of natural gas.

• MMcfe. One million cubic feet of natural gas equivalents.

• NYMEX. The New York Mercantile Exchange.

• PDP. Proved developed producing.

• 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.

3

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

(Dollars in thousands, except share and per share data)	December 31, 2007			September 30, 2008 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	11,687		$	7,540
Accounts receivable, net		66,105			72,566
Inventories		19,480			25,364
Deferred income taxes		19,128			23,696
Prepaid expenses		4,304			3,254
Derivative instruments		—			6,302
Total current assets		120,704			138,722
Property and equipment—at cost, net		50,747			69,954
Oil & gas properties, using the full cost method:
Proved		1,457,822			1,641,296
Unproved (excluded from the amortization base)		25,327			30,447
Work in progress (excluded from the amortization base)		19,274			51,009
Accumulated depletion and depreciation		(200,577	)		(267,888	)
Total oil & gas properties		1,301,846			1,454,864
Funds held in escrow		5,224			2,343
Derivative instruments		—			27,537
Other assets		52,377			49,926
	$	1,530,898		$	1,743,346
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	77,540		$	95,105
Accrued interest payable		14,741			14,187
Revenue distribution payable		21,471			26,563
Current maturities of long-term debt and capital leases		6,921			12,904
Derivative instruments		54,307			61,937
Total current liabilities		174,980			210,696
Long-term debt and capital leases, less current maturities		459,826			552,342
Senior notes, net		647,490			647,627
Derivative instruments		96,227			123,972
Deferred compensation		2,017			1,640
Asset retirement obligations		29,684			31,348
Deferred income taxes		17,496			41,720
Commitments and contingencies (note 8)
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 September 30, 2008, respectively		9			9
Additional paid in capital		100,918			100,918
Retained earnings		76,090			121,575
Accumulated other comprehensive loss, net of taxes		(73,839	)		(88,501	)
		103,178			134,001
	$	1,530,898		$	1,743,346

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended September 30,						Nine months ended September 30,
(Dollars in thousands, except share and per share data)	2007 (unaudited)			2008 (unaudited)			2007 (unaudited)			2008 (unaudited)
Revenues:
Oil and gas sales	$	98,565		$	148,669		$	256,873		$	427,365
Loss from oil and gas hedging activities		(4,284	)		(2,315	)		(10,784	)		(91,670	)
Service company sales		7,505			9,655			13,419			25,930
Total revenues		101,786			156,009			259,508			361,625
Costs and expenses:
Lease operating		27,033			32,066			77,835			86,148
Production tax		6,803			9,822			18,265			28,338
Depreciation, depletion and amortization		22,259			25,086			63,211			73,674
General and administrative		5,727			4,877			15,911			18,958
Loss on impairment of ethanol plant		—			2,900			—			2,900
Service company expenses		6,669			8,943			11,800			24,275
Total costs and expenses		68,491			83,694			187,022			234,293
Operating income		33,295			72,315			72,486			127,332
Non-operating income (expense):
Interest expense		(22,728	)		(21,661	)		(65,021	)		(64,282	)
Non-hedge derivative gains (losses)		(2,399	)		77,186			(6,228	)		10,005
Other income		348			186			815			1,340
Net non-operating income (expense)		(24,779	)		55,711			(70,434	)		(52,937	)
Income before income taxes		8,516			128,026			2,052			74,395
Income tax expense		3,254			49,522			764			28,910
Net income	$	5,262		$	78,504		$	1,288		$	45,485
Earnings per share
Net income per share (basic and diluted)	$	6.00		$	89.51		$	1.47		$	51.86
Weighted average number of shares used in calculation of basic and diluted net income per share		877,000			877,000			877,000			877,000

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

5

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Nine months ended September 30,
(Dollars in thousands)	2007 (unaudited)			2008 (unaudited)
Cash flows from operating activities
Net income	$	1,288		$	45,485
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		63,211			73,674
Service company depreciation, depletion & amortization		174			1,070
Loss on impairment of ethanol plant		—			2,900
Deferred income taxes		764			28,910
Unrealized (gain) loss on ineffective portion of hedges		3,126			(6,565	)
Change in fair value of non hedge derivative instruments		6,228			(10,005	)
Other		799			965
Change in assets and liabilities
Accounts receivable		(5,793	)		(312	)
Inventories		1,849			(5,884	)
Prepaid expenses and other assets		619			3,809
Accounts payable and accrued liabilities		6,171			5,923
Revenue distribution payable		(21	)		5,092
Deferred compensation		929			1,031
Net cash provided by operating activities		79,344			146,093
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(162,472	)		(243,544	)
Acquisition of businesses, net of cash acquired		(21,678	)		—
Proceeds from dispositions of property and equipment and oil and gas properties		298			1,767
Cash in escrow		785			1,066
Settlement of non-hedge derivative instruments		(668	)		(5,953	)
Net cash used in investing activities		(183,735	)		(246,664	)
Cash flows from financing activities
Proceeds from long-term debt		99,879			101,925
Repayment of long-term debt and acquisition financing		(303,159	)		(3,845	)
Proceeds from senior notes		322,329			—
Principal payments under capital lease obligations		(129	)		(167	)
Settlement of derivative instruments acquired		(1,106	)		144
Fees paid related to financing activities		(7,205	)		(1,633	)
Net cash provided by financing activities		110,609			96,424
Net increase (decrease) in cash and cash equivalents		6,218			(4,147	)
Cash and cash equivalents at beginning of period		8,803			11,687
Cash and cash equivalents at end of period	$	15,021		$	7,540
Supplemental cash flow information
Cash paid during the period for:
Interest, net of capitalized interest	$	47,088		$	62,492
Income taxes		—			—

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

6

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(continued)

Supplemental disclosure of non-cash investing and financing activities (dollars in thousands)

During the nine months ended September 30, 2007 and 2008, the Company entered into capital lease obligations of $21 and $586, respectively, for the purchase of machinery and equipment.

Non-cash additions to oil and gas properties include $1,113 and $3,288, respectively, as of September 30, 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, as of September 30, 2007, non-cash additions to oil and gas properties include $15,597 related to final settlement of the Calumet acquisition. Non-cash additions to property and equipment as of September 30, 2008 also include $1,707 related to final settlement of the Green Country Supply acquisition.

During the nine months ended September 30, 2007 and 2008, the Company recorded an asset and related liability of $209 and $655, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $1,180 and $1,019 was capitalized during the nine months ended September 30, 2007 and 2008, respectively, related to the development of unproved oil and gas leaseholds. Interest of $32 and $148 was capitalized during the nine months ended September 30, 2007 and 2008, respectively, related to the construction of the Company’s office building.

7

Chaparral Energy, Inc. and subsidiaries

Notes to Consolidated Financial Statements

(dollars in thousands, except per share data)

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

Chaparral Energy, Inc. and its 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.

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X and do not include all of the financial information and disclosures required by GAAP. The financial information as of September 30, 2008 and for the three months and nine months ended September 30, 2007 and 2008 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals and an impairment charge, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2008 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2008.

The consolidated interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations contained in our Form 10-K filed with the Securities and Exchange Commission on March 31, 2008.

Principles of consolidation

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

Reclassifications

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

Use of estimates

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

Fair value measurements

In September 2006, the Financial Accounting Standards Board (“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.

8

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 (“FSP”) 157-2,Effective Date of FASB Statement No. 157, 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—which was not material. 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, 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 third quarter 2008 financial reporting and results. There was no material impact on our financial position or results of operations for the nine months ended September 30, 2008.

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.

Accounts receivable

Accounts receivable consisted of the following at December 31, 2007 and September 30, 2008:

	December 31, 2007			September 30, 2008
Joint interests	$	19,319		$	18,057
Accrued oil and gas sales		40,377			47,800
Service company sales		4,827			6,060
Other		1,920			1,419
Allowance for doubtful accounts		(338	)		(770	)
	$	66,105		$	72,566

9

Inventories

Inventories are comprised of equipment used in developing oil and gas properties, oil and gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the specific identification method and average cost method, respectively. Oil and gas product inventories are stated at the lower of production cost or market. The Company regularly reviews inventory quantities on hand and records provisions for excess or obsolete inventory. Inventories at December 31, 2007 and September 30, 2008 consist of the following:

	December 31, 2007		September 30, 2008
Equipment inventory	$	3,027	$	7,521
Oil and gas product		3,221		3,323
Service company inventory for resale		13,232		14,520
	$	19,480	$	25,364

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:

	December 31, 2007		September 30, 2008
Title defect escrow from acquisitions	$	383	$	689
Plugging and abandonment escrow		1,635		1,654
Post closing adjustment escrow from acquisition		3,206		—
	$	5,224	$	2,343

Upon clearing of the title defects, the amount in title defect escrow account 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 own 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. 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 through September 30, 2008.

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. During the nine months ended September 30, 2008, we recorded a valuation allowance of $133 for Federal NOL carryforwards we do not expect to realize before they expire.

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

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized no material adjustment in our tax liability for unrecognized income tax benefits. If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. We have not accrued interest related to uncertain tax positions as of September 30, 2007 or 2008.

The tax years 1998-2007 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Recently issued accounting standards

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”). This Statement permits the election to carry financial instruments and certain other items similar to financial instruments at fair value on the balance sheet, with all changes in fair value reported in earnings. We adopted SFAS 159 effective January 1, 2008. During the first nine months of 2008, we did not make the fair value election for any financial instruments not already carried at fair value in accordance with other accounting standards, so the adoption of SFAS 159 did not impact our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS 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. We are currently assessing the impact, if any, the adoption of SFAS No. 141(R) may have on any future acquisitions.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51 (“SFAS 160”) . This Statement requires that accounting and reporting for minority interests be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008. 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”). This Statement addresses concerns that the existing disclosure requirements in SFAS 133, Accounting for Derivatives and Hedging Activities, as Amended (“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, with early application encouraged. We are currently assessing the impact, if any, of the adoption of SFAS 161.

Note 2: Derivative financial instruments

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

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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 connection with 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.

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

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

All derivative financial instruments are recorded on the balance sheet at fair value. 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 party to our revolving credit facility. We believe all of these institutions are acceptable credit risks.

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			September 30, 2008
Derivative assets (liabilities):
Gas swaps	$	4,709		$	6,437
Oil swaps		(155,782	)		(191,358	)
Gas collars		—			14,099
Oil collars		—			15,025
Natural gas basis differential swaps		539			3,727
	$	(150,534	)	$	(152,070	)

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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:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Reclassification of settled contracts	$	(5,286	)	$	(36,978	)	$	(7,658	)	$	(98,235	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		1,002			34,663			(3,126	)		6,565
	$	(4,284	)	$	(2,315	)	$	(10,784	)	$	(91,670	)

Based upon market prices at September 30, 2008 and assuming no future change in the market, the Company expects to charge $36,286 of the balance in accumulated other comprehensive loss to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of September 30, 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). Non-hedge derivative gains (losses) in the consolidated statements of operations is comprised of the following:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Unrealized gain (loss) on non-qualified commodity price swaps	$	(1,620	)	$	42,525		$	(7,430	)	$	(16,355	)
Unrealized gain on non-designated costless collars		—			37,682			—			29,125
Unrealized gain (loss) on natural gas basis differential contracts		(530	)		(1,627	)		1,870			3,188
Loss on settlement of non-qualified commodity price swaps		—			(3,021	)		—			(8,227	)
Gain on settlement of non-designated costless collars		—			125			—			125
Gain (loss) on settlement of natural gas basis differential contracts		(249	)		1,502			(668	)		2,149
	$	(2,399	)	$	77,186		$	(6,228	)	$	10,005

Derivative settlement payments of $8,759 and $15,769 were included in accounts payable and accrued liabilities at December 31, 2007 and September 30, 2008, respectively. Derivative settlement receivables of $51 were included in accounts receivable at December 31, 2007. There were no derivative settlement receivables included in accounts receivable at September 30, 2008.

We have no Level 1 assets or liabilities as of September 30, 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.

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 September 30, 2008
Derivative assets	$	23,119		$	30,305	$	(19,585	)	$	33,839
Derivative liabilities		(205,494	)		—		19,585			(185,909	)
Total derivative assets (liabilities)	$	(182,375	)	$	30,305	$	—		$	(152,070	)

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

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Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at September 30, 2008, were:

Nine Months Ended September 30, 2008	Net Derivative Assets (Liabilities)
Beginning balance	$	172
Total realized and unrealized gains (losses) included in net loss		30,773
Purchases, issuances, and settlements		(640	)
Ending balance	$	30,305
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	$	30,049

Note 3: Asset retirement obligations

The Company’s asset retirement obligations relate to estimated future plugging and abandonment expenses or disposal of its oil and gas properties and related facilities. These obligations to abandon and restore properties are based upon estimated future costs which may change based upon future inflation rates and changes in statutory remediation rules. The following table provides a summary of the Company’s asset retirement obligations for the nine months ended September 30, 2008:

	Nine Months Ended September 30, 2008
Beginning balance	$	30,684
Liabilities incurred in current period		655
Liabilities settled in current period		(964	)
Accretion expense		1,973
	$	32,348
Less current portion		(1,000	)
	$	31,348

Note 4: Long-term debt

Long-term debt at December 31, 2007 and September 30, 2008 consisted of the following:

	December 31, 2007		September 30, 2008
Revolving credit line with banks (1)	$	447,000	$	537,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 5.00% to 7.283%, due December 2008 through September 2021; collateralized by real property		9,644		13,378
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.62% to 9.387%, due January 2008 through September 2013; collateralized by automobiles, machinery and equipment		9,925		14,271
		466,569		564,649
Less current maturities		6,762		12,664
	$	459,807	$	551,985

(1) In October 2006, the Company entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010. Availability under our Credit Agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. Effective May 14, 2008, the borrowing base was adjusted to $600,000. The Company and the banks have agreed to delay the borrowing base redetermination scheduled for November 1, 2008 until December 10, 2008. Interest is paid at least every three months on $447,000 based upon LIBOR as defined in the credit agreement as of December 31, 2007 (effective rate of 7.163%) and on $537,000 based upon LIBOR as of September 30, 2008 (effective rate of 6.446%). 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.

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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 all obligations under capital leases, as defined in the First Amendment to our Credit Agreement. The amended Credit Agreement requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

• 2.75 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarters 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 quarter thereafter.

We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2008.

Subsequent to September 30, 2008, the Company has drawn an additional $15,000 under the Credit Agreement.

Note 5: Related party transactions

In September 2006, Chesapeake Energy Corporation (“Chesapeake”) acquired a 31.9% beneficial interest in the Company, which is now held by its wholly owned subsidiary, CHK Holdings, L.L.C., 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 $2,483 and $964, respectively for the three months ended September 30, 2007 and $2,055 and $854, respectively for the three months ended September 30, 2008. The Company received revenues and incurred joint interest billings on these properties of $5,863 and $3,289, respectively for the nine months ended September 30, 2007 and $6,523 and $2,184, respectively during the nine months ended September 30, 2008. In addition, Chesapeake participates in ownership of properties operated by the Company. The Company paid revenues and recorded joint interest billings of $393 and $518, respectively during the three months ended September 30, 2007 and $1,238 and $713, respectively during the three months ended September 30, 2008. The Company paid revenues and recorded joint interest billings of $1,090 and $904, respectively during the nine months ended September 30, 2007 and $2,351 and $2,188, respectively during the nine months ended September 30, 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 $1,848 and $350, respectively as of September 30, 2008.

Note 6: 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 the 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 immediately at a redemption date of January 1 or July 1, but in no event may the redemption be later than 2 ¹/2 months after the end of the year in which vesting occurs. 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, 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.

Compensation expense is recognized over the vesting period of the phantom stock and is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Such expense is calculated net of forfeitures estimated based on the Company’s historical and expected turnover rates. The Company recognized deferred compensation expense of $468, net of $234 capitalized, resulting in a reduction in net income for the three months ended September 30, 2007. Due to a reduction in the fair value of the phantom stock from June 30, 2008 to September 30, 2008, the Company recognized deferred compensation gain of $1,362, net of $671 capitalized, resulting in an increase in net income for the three months ended September 30, 2008. The Company recognized deferred compensation expense of $929, net of $463 capitalized, and $1,031, net of $501 capitalized, resulting in a reduction in net income for the nine months ended September 30, 2007 and 2008, respectively.

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A summary of the Company’s phantom stock activity as of December 31, 2007, and changes during the first nine months of fiscal year 2008 is presented in the following table:

	Fair Value		Phantom Shares		Weighted average remaining contract term	Aggregate intrinsic value
	(Per unit)
Unvested and total outstanding at December 31, 2007	$	16.54	200,843
Granted	$	16.54	31,158
Vested	$	16.54	—
Forfeited	$	16.54	(11,587	)
Unvested and total outstanding at September 30, 2008	$	23.78	220,414		1.75	$	5,241

Upon vesting, the Company may redeem the shares, or the participant may defer redemption until a later January 1 or July 1, but in any event redemption must occur no later than 2 ¹/2 months after the end of the year in which vesting occurs. Accordingly, the contract term and the vesting period are the same. There are no vested shares as of September 30, 2008.

The fair value of each award is estimated on the date of grant and subsequently remeasured at the end of each reporting period using the Black-Scholes option pricing model. The assumptions used for the nine months ended September 30, 2008 are as follows:

Dividend yield	0.0	%
Volatility	114.0	%
Risk-free interest rate	2.98	%
Expected life (in years)	.25-4.25

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

As of September 30, 2008, there was approximately $1,692 of total unrecognized compensation cost related to unvested phantom shares that is expected to be recognized over a weighted-average period of 1.75 years. Deferred compensation cost of $1,909 that will vest within the next twelve months was included in accounts payable and accrued liabilities as of September 30, 2008. There was no deferred compensation cost included in accounts payable as of December 31, 2007, as there were no shares vesting within the next twelve months.

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Note 7: Segment information

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

	Exploration and Production		Service Company			Intercompany Eliminations			Consolidated Total
For the Three Months Ended September 30, 2007:
Revenues	$	94,281	$	14,066		$	(6,561	)	$	101,786
Intersegment revenues		—		(6,561	)		6,561			—
Total revenues		94,281		7,505			—			101,786
Income before income taxes	$	7,480	$	1,319		$	(283	)	$	8,516
For the Three Months Ended September 30, 2008:
Revenues	$	146,354	$	22,105		$	(12,450	)	$	156,009
Intersegment revenues		—		(12,450	)		12,450			—
Total revenues		146,354		9,655			—			156,009
Income before income taxes	$	126,876	$	1,955		$	(805	)	$	128,026
For the Nine Months Ended September 30, 2007:
Revenues	$	246,089	$	24,490		$	(11,071	)	$	259,508
Intersegment revenues		—		(11,071	)		11,071			—
Total revenues		246,089		13,419			—			259,508
Income before income taxes	$	111	$	2,439		$	(498	)	$	2,052
For the Nine Months Ended September 30, 2008:
Revenues	$	335,695	$	54,324		$	(28,394	)	$	361,625
Intersegment revenues		—		(28,394	)		28,394			—
Total revenues		335,695		25,930			—			361,625
Income (loss) before income taxes	$	71,948	$	3,804		$	(1,357	)	$	74,395
As of December 31, 2007:
Total Assets	$	1,529,452	$	28,092		$	(26,646	)	$	1,530,898
As of September 30, 2008:
Total Assets	$	1,740,910	$	36,210		$	(33,774	)	$	1,743,346

Note 8: Commitments and contingencies

Standby letters of credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. The Company had various Letters outstanding totaling $1,690 and $1,810 as of December 31, 2007 and September 30, 2008, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 6.446% at September 30, 2008) for all amounts paid by the lenders under the Letters. No interest was paid by the Company on the Letters during the three and nine months ended September 30, 2007 and 2008.

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 results of operations.

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 defend our position. Pretrial discovery is ongoing. 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. Written and documentary discovery is ongoing and depositions are underway. As of September 30, 2008, the recorded receivable was $14,406 and was included in other assets on the consolidated balance sheet.

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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 between $10,350 and $11,900. We anticipate our insurance policy will cover 100% of these costs up to a maximum of $35,000, with the $650 insurance retention and deductible being payable by us. During the third quarter, we received $4,845 from our insurer for costs incurred through June 30, 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.

Agreement and Plan of Merger

On July 14, 2008, the Company entered into an Agreement and Plan of Merger (the “Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge will merge with and into the Company’s wholly owned subsidiary, Chaparral Exploration, LLC (the “Merger”). At the effective time of the Merger, each share of Edge’s common stock will be converted automatically into the right to receive 0.2511 shares of the Company’s common stock, and each share of Edge’s 5.75% Series A Cumulative Convertible Perpetual Preferred Stock will be converted automatically into the right to receive one share of the Company’s 5.75% Series A Cumulative Convertible Perpetual Preferred Stock.

The Agreement, which was approved by the Company’s Board of Directors and its stockholders and Edge’s Board of Directors, provides that, following the effective time of the Merger, at least two members of Edge’s Board of Directors will join the Company’s Board of Directors.

Completion of the Merger is conditioned upon, among other things, adoption of the Agreement by Edge’s common stockholders and the accuracy of representations and warranties (subject to materiality exceptions) as of the date of the Agreement and the closing date of the Merger, and the performance by the parties in all material respects of their covenants under the Agreement. Each party has the right to terminate the merger agreement, subject to certain conditions, if the merger has not been completed by December 31, 2008.

The Agreement contains various termination rights for both parties. Upon termination of the Agreement under specified circumstances, the Company or Edge will be required to pay the other party a termination fee of $15,000. With certain exceptions, all costs and expenses incurred in connection with the Agreement will be paid by the party incurring such expenses, whether or not the Merger is consummated. The Agreement includes provisions limiting the maximum aggregate liability of either party to $25,000 in the event the Merger is not consummated.

Stock Purchase Agreement

On July 14, 2008, the Company entered into a stock purchase agreement (the “Stock Purchase Agreement”) with Magnetar Financial LLC, on behalf of itself and one or more of its affiliates (“Magnetar”), pursuant to which Magnetar will purchase and the Company will sell 1,500,000 shares of its Series B Convertible Preferred Stock, par value $0.01 per share, for a purchase price of $150,000. At the closing of the Stock Purchase Agreement, the Company will pay Magnetar a closing fee of $750 and reimburse Magnetar’s out of pocket expenses up to $500. The closing of the Stock Purchase Agreement is conditioned upon the closing of the Merger and upon certain other customary closing conditions.

Note 9: Comprehensive income

Components of comprehensive income (loss), net of related tax, are as follows for the three and nine months ended September 30, 2007 and 2008:

	Three months ended September 30,					Nine months ended September 30,
	2007			2008		2007			2008
Net income	$	5,262		$	78,504	$	1,288		$	45,485
Unrealized gain (loss) on hedges		(6,905	)		147,180		(25,745	)		(74,978	)
Reclassification adjustment for hedge losses included in net income		3,060			22,704		4,516			60,316
Comprehensive income (loss)	$	1,417		$	248,388	$	(19,941	)	$	30,823

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following in conjunction with our financial statements contained herein and our Form 10-K filed with the Securities and Exchange Commission on March 31, 2008.

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. Please refer to “Forward-Looking Statements” for an explanation of these types of statements. In addition, actual results may differ due to the factors set forth under Part II, Item 1A. “Risk Factors” included in this report, in our Annual Report on Form 10-K for the year ended December 31, 2007, and under the heading “Risk Factors” in our prospectus included in our Registration Statement on Form S-4 declared effective on September 9, 2008.

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 and unproved reserves, development and exploratory drilling opportunities, and EOR projects.

During 2008, there has been extreme volatility and disruption in the capital and credit markets. During the third and fourth quarters of 2008, the volatility and disruption have created conditions that may adversely affect the financial condition of the lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, and our oil and natural gas purchasers.

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 natural 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 natural gas activities.

Oil and natural gas prices fluctuate widely. The prices we receive for our oil and natural 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 natural gas reserves; and

• operating results for oil and natural gas activities.

We generally enter into derivative contracts for a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. See “Quantitative and Qualitative Disclosures about Market Risk” below for a discussion of our derivative contracts.

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 13.5%, 10.8% and 8.1% during 2008, 2009 and 2010, respectively. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

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

• the quantity of our proved oil and natural gas reserves;

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

• the value of our derivative positions;

19

• 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.

During the third quarter of 2008, quarterly production was 10,502 MMcfe, a 1.0% decrease over production levels in the third quarter of 2007, partially due to seasonal weather disruptions. Despite slightly lower production and higher operating costs, the revenue impact of higher commodity prices caused operating income to increase to $72.3 million during the third quarter of 2008 compared to $33.3 million during the comparable quarter of 2007. In addition, non-hedge derivative gains of $77.2 million resulted in net income of $78.5 million in the third quarter of 2008 as compared to net income of $5.3 million during the same period in 2007.

All of our expenses, with the exception of general and administrative, increased on both an absolute and per Mcfe basis during the third quarter of 2008 compared to the comparable period in 2007 due to higher overall industry costs.

We expanded our oil and natural gas property capital expenditure budget for 2008 from $209.0 million to $269.0 million during the second quarter of 2008 due to increased capital resources. From January 1, 2008 through September 30, 2008, we spent $179.4 million on exploratory and development activities and approximately $44.6 million on acquisitions of oil and natural gas properties. We currently expect our oil and gas capital expenditures to be between $60.0 and $65.0 for the fourth quarter.

The following are recent developments that have impacted the results of operations or liquidity discussed below, 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. 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.

Oil and natural gas prices declined significantly during October 2008, which will reduce our cash flows from operations in the fourth quarter and in future periods in which prices remain at or below the current levels. The commodity price swaps and costless collars that cover approximately 70% of our expected natural gas production in the fourth quarter and approximately 80% of our expected oil production in the fourth quarter will, however, become more valuable if prices continue to decline in the fourth quarter.

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, and development activities are capitalized. 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. Under the SEC’s full cost accounting rules, we review the carrying value of our proved oil and natural gas properties each quarter. These rules generally require that we price our future oil and natural gas production at the oil and natural gas prices in effect at the end of each fiscal quarter to determine a ceiling value for our properties. The rules require a write down if our capitalized costs exceed the allowed “ceiling.” Given the volatility of oil and natural gas prices, it is likely that our estimated discounted future net revenue from proved oil and natural gas reserves will fluctuate in the near term. If oil and gas prices continue to decline significantly in the future, write downs of our oil and natural gas properties could occur. Write downs by these rules do not directly impact our cash flows from operating activities. At September 30, 2008 the ceiling with respect to our oil and natural gas properties exceeded the net capitalized costs of these properties by approximately $600.0 million.

• Credit Facility. Our current credit facility is a revolving credit facility in the amount of $600.0 million. At November 14, 2008, we had $552.0 million outstanding under the revolving credit facility and $1.8 million was utilized by outstanding letters of credit. The revolving credit facility matures October 31, 2010. Should current credit market volatility be prolonged for several years, future extensions of our credit facility may contain terms that are less favorable than those of our current credit facility.

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• 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 receipt of $2 of Oklahoma 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 September 30, 2008, we have received $2.7 million of this credit.

• Oklahoma Ethanol. We own a 66.67% interest in Oklahoma Ethanol LLC, a joint venture to construct and operate an ethanol production plant in Blackwell, Oklahoma. The minority owner, Oklahoma Sustainable Energy LLC, is no longer able to participate in the joint venture because project financing did not close by September 15, 2008. 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 $2.9 million, which was the amount of our investment in the plant through September 30, 2008.

• Agreement and Plan of Merger. On July 14, 2008, we entered into an Agreement and Plan of Merger (the “Agreement”) with Edge Petroleum Corporation (“Edge”), whereby Edge will merge with and into the Company’s wholly owned subsidiary, Chaparral Exploration, L.L.C. (the “Merger”). At the effective time of the Merger, each share of Edge’s common stock will be converted automatically into the right to receive 0.2511 shares of our common stock, and each share of Edge’s 5.75% Series A Cumulative Convertible Perpetual Preferred Stock will be converted automatically into the right to receive one share of our 5.75% Series A Cumulative Convertible Perpetual Preferred Stock. The initial conversion price per share of our preferred stock will be $65.95 per share of our common stock. Upon termination of the Agreement under specified circumstances, we or Edge will be required to pay the other party a termination fee of $15 million.

• Stock Purchase Agreement. On July 14, 2008, we entered into a stock purchase agreement (the “Stock Purchase Agreement”) with Magnetar Financial LLC, on behalf of itself and one or more of its affiliates (“Magnetar”), pursuant to which Magnetar will purchase and we will sell 1,500,000 shares of our Series B Convertible Preferred Stock, par value $0.01 per share, for a purchase price of $150.0 million. The closing of the Stock Purchase Agreement is conditioned upon the closing of the Merger and upon certain other customary closing conditions.

• 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 between $10.4 and $11.9 million. We anticipate our insurance policy will cover 100% of these costs up to a maximum of $35.0 million, with the $0.7 million insurance retention and deductible being payable by us. During the third quarter, we received $4.8 million from our insurer for costs incurred through June 30, 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 $5.0 million for costs incurred through September 30, 2008.

Results of Operations

Comparison of three months ended September 30, 2008 to three months ended September 30, 2007.

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

	Three Months Ended September 30,				Percentage Change
	2007		2008
Oil and natural gas sales (dollars in thousands)
Oil	$	67,577	$	106,816	58.1	%
Natural gas		30,988		41,853	35.1	%
Total	$	98,565	$	148,669	50.8	%
Production
Oil (MBbls)		926		962	3.9	%
Natural gas (MMcf)		5,053		4,730	(6.4	)%
MMcfe		10,609		10,502	(1.0	)%
Average sales prices (excluding hedging)
Oil per Bbl	$	72.98	$	111.04	52.2	%
Natural gas per Mcf		6.13		8.85	44.4	%
Mcfe		9.29		14.16	52.4	%

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Oil sales increased 58.1% from $67.6 million during the three months ended September 30, 2007 to $106.8 million during the same period in 2008. This increase was due to a 3.9% increase in production volumes to 962 MBbls, and a 52.2% increase in average oil prices to $111.04 per barrel. Natural gas sales revenues increased 35.1% from $31.0 million during the three months ended September 30, 2007 to $41.9 million during the same period in 2008. This increase was due to a 44.4% increase in average natural gas prices, partially offset by a decrease in production volumes to 4,730 MMcf. Gas production for the three months ended September 30, 2008 decreased primarily due to seasonal weather disruptions, delays in receiving services and products, and normal production decline rates.

Production volumes by area were as follows (MMcfe):

	Three Months Ended September 30,		Percentage Change
	2007	2008
Mid Continent	7,023	7,209	2.6	%
Permian	1,586	1,598	0.8	%
Gulf Coast	877	803	(8.4	)%
Ark-La-Tex	475	420	(11.6	)%
North Texas	402	241	(40.0	)%
Rockies	246	231	(6.1	)%
Totals	10,609	10,502	(1.0	)%

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

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

	Three Months Ended September 30,
	2007			2008
	(dollars in thousands)
Gain (loss) from oil and natural gas hedging activities:
Hedge settlements	$	(5,286	)	$	(36,978	)
Hedge ineffectiveness		1,002			34,663
Total	$	(4,284	)	$	(2,315	)

Due to high overall commodity prices during the third quarter of 2008, our loss on hedge settlements was $37.0 million. This was partially offset by a $34.7 million gain on hedge ineffectiveness resulting from lower NYMEX forward strip oil and natural gas prices at September 30, 2008 compared to June 30, 2008. Natural gas volumes hedged increased by 5,010 MMBtu from September 30, 2007 to September 30, 2008. As a result of these changes in commodity prices and volumes hedged, our loss from hedging activities was $2.3 million in the third quarter of 2008 compared to a loss of $4.3 in the third quarter of 2007.

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

	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge
Oil (per Bbl):
Three months ended September 30, 2007	$	72.98	$	63.31	86.7	%
Three months ended September 30, 2008		111.04		81.18	73.1	%
Natural gas (per Mcf):
Three months ended September 30, 2007	$	6.13	$	6.86	111.9	%
Three months ended September 30, 2008		8.85		7.10	80.2	%

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Costs and Expenses. The following table presents information about our operating expenses for the third quarter of 2007 and 2008:

	Amount						Per Mcfe
	Three Months Ended September 30,				Percent Change		Three Months Ended September 30,				Percent Change
	2007		2008				2007		2008
	(dollars in thousands)
Lease operating expenses	$	27,033	$	32,066	18.6	%	$	2.55	$	3.05	19.6	%
Production taxes		6,803		9,822	44.4	%		0.64		0.94	46.9	%
Depreciation, depletion and amortization		22,259		25,086	12.7	%		2.10		2.39	13.8	%
General and administrative		5,727		4,877	(14.8	)%		0.54		0.46	(14.8	)%

Lease operating expenses – Increase was primarily due to higher oilfield service costs, including costs associated with artificial lift on oil properties, and increases in the net number of producing wells. Per unit expenses were higher in the third quarter of 2008 than the same quarter of 2007 due to a $4.2 million increase in workover activity, and a $1.7 million increase in electricity and fuel costs combined with lower production volumes.

Production taxes (which include ad valorem taxes) – Increase was primarily due to a 52.4% increase in averaged realized prices, partially offset by a decrease of 1.0% in production volumes compared to the same period in 2007.

Depreciation, depletion and amortization (“DD&A”) – Increase of $2.8 million was primarily due to an increase in DD&A on oil and natural gas properties of $2.1 million. For oil and natural gas properties, an increase in the DD&A rate per equivalent unit of production caused an increase in expense of $2.3 million, which was partially offset by a decrease of $0.2 million due to lower production volumes. Our DD&A rate on oil and natural gas properties per equivalent unit of production increased $0.22 to $2.15 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses – Decrease of $0.9 million was primarily due to a reduction of the accrual for deferred compensation costs of $1.2 million that were previously expensed. As a result, deferred compensation expense decreased by $1.7 million in the third quarter of 2008 compared to the same period of 2007. G&A expense is net of $2.5 million in the third quarter of 2008 and $2.8 million in the same period of 2007 capitalized as part of our exploration and development activities.

Interest Expense.Interest expense decreased during the third quarter of 2008 by $1.1 million, or 4.7%, compared to the same period in 2007 primarily as a result of lower interest rates paid, somewhat offset by increased levels of borrowings. The following table presents interest expense for the third quarter of 2007 and 2008:

	Three Months Ended September 30,
	2007		2008
	(dollars in thousands)
Revolver interest	$	7,157	$	5,836
8 1/2% Senior Notes, due 2015		7,073		7,089
8 7/8% Senior Notes, due 2017		7,367		7,433
Bank fees and other interest		1,131		1,303
	$	22,728	$	21,661

Non-hedge derivative gains (losses). Non-hedge derivative gains were $77.2 million during the three months ended September 30, 2008 and are comprised of gains of $39.5 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, and gains of $37.8 million on collars that were not designated as hedges, partially offset by net losses of $0.1 million related to natural gas basis differential swaps. Non-hedge derivative losses were $2.4 million during the three months ended September 30, 2007 and are comprised of losses of $1.6 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges and $0.8 million related to natural gas basis differential swaps.

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, depreciation, and general and administrative expenses. We recognized $9.6 million in service company revenue in the third quarter of 2008, including sales of $0.6 million to Edge, with corresponding service company expense of $8.9 million, for a net profit of $0.7 million. We recognized $7.5 million in service company revenue in the third quarter of 2007 with corresponding service company expense of $6.7 million, for a net profit of $0.8 million.

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Loss on impairment of ethanol plant. We own 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. 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 $2.9 million, which was the amount of our investment in the ethanol plant through September 30, 2008.

Comparison of nine months ended September 30, 2008 to nine months ended September 30, 2007.

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

	Nine Months Ended September 30,				Percentage Change
	2007		2008
Oil and natural gas sales (dollars in thousands)
Oil	$	160,059	$	297,143	85.6	%
Natural gas		96,814		130,222	34.5	%
Total	$	256,873	$	427,365	66.4	%
Production
Oil (MBbls)		2,507		2,785	11.1	%
Natural gas (MMcf)		15,246		14,583	(4.3	)%
MMcfe		30,288		31,293	3.3	%
Average sales prices (excluding hedging)
Oil per Bbl	$	63.84	$	106.69	67.1	%
Natural gas per Mcf		6.35		8.93	40.6	%
Mcfe		8.48		13.66	61.1	%

Oil sales increased 85.6% from $160.1 million during the nine months ended September 30, 2007 to $297.1 million during the same period in 2008. This increase was due to an 11.1% increase in production volumes to 2,785 MBbls and a 67.1% increase in average oil prices to $106.69 per barrel. Natural gas sales revenues increased 34.5% from $96.8 million during the nine months ended September 30, 2007 to $130.2 million during the same period in 2008. This increase was due to a 40.6% increase in average natural gas prices, partially offset by a 4.3% decline in production volumes to 14,583 MMcf. Oil production for the nine months ended September 30, 2008 increased primarily due to our drilling program and enhancements of our existing properties, partially offset by decreased production on existing producing properties due to increased seasonal weather disruptions during the first quarter of 2008. Gas production for the nine months ended September 30, 2008 decreased primarily due to seasonal weather disruptions during the third quarter of 2008, delays in receiving services and products, and normal production decline rates.

Production volumes by area were as follows (MMcfe):

	Nine Months Ended September 30,		Percentage Change
	2007	2008
Mid Continent	19,749	21,037	6.5	%
Permian	4,803	4,873	1.5	%
Gulf Coast	2,613	2,537	(2.9	)%
Ark-La-Tex	1,366	1,320	(3.4	)%
North Texas	1,045	821	(21.4	)%
Rockies	712	705	(1.0	)%
Totals	30,288	31,293	3.3	%

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

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

	Nine Months Ended September 30,
	2007			2008
	(dollars in thousands)
Gain (loss) from oil and natural gas hedging activities:
Hedge settlements	$	(7,658	)	$	(98,235	)
Hedge ineffectiveness		(3,126	)		6,565
Total	$	(10,784	)	$	(91,670	)

Due to high overall commodity prices during the first nine months of 2008, our loss on hedge settlements was $98.2 million. This was partially offset by a $6.6 million gain on hedge ineffectiveness. Natural gas volumes hedged increased by 5,010 MMBtu from September 30, 2007 to September 30, 2008. As a result of these changes in commodity prices and volumes hedged, our loss from hedging activities was $91.7 million in the first nine months of 2008 compared to a loss of $10.8 million in the first nine months of 2007.

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

	Average Price				Hedged to Non-Hedged Price
	Without Hedge		With Hedge
Oil (per Bbl):
Nine months ended September 30, 2007	$	63.84	$	58.87	92.2	%
Nine months ended September 30, 2008		106.69		78.15	73.2	%
Natural gas (per Mcf):
Nine months ended September 30, 2007	$	6.35	$	6.67	105.0	%
Nine months ended September 30, 2008		8.93		7.64	85.6	%

Costs and Expenses. The following table presents information about our operating expenses for the first nine months of 2007 and 2008:

	Amount						Per Mcfe
	Nine Months Ended September 30,				Percent Change		Nine Months Ended September 30,				Percent Change
(dollars in thousands)	2007		2008				2007		2008
Lease operating expenses	$	77,835	$	86,148	10.7	%	$	2.57	$	2.75	7.0	%
Production taxes		18,265		28,338	55.1	%		0.60		0.91	51.7	%
Depreciation, depletion and amortization		63,211		73,674	16.6	%		2.09		2.35	12.4	%
General and administrative		15,911		18,958	19.2	%		0.53		0.61	15.1	%

Lease operating expenses – Increase was primarily due to higher oilfield service costs, including costs associated with artificial lift on oil properties, and increases in the net number of producing wells. Per unit expenses were higher in the nine months ended of 2008 than the same period of 2007 primarily due to a $2.4 million increase in workover activity, a $2.2 million increase in electricity and fuel costs, and a $3.4 million increase in other field service costs.

Production taxes (which include ad valorem taxes) – Increase was primarily due to 61.1% higher averaged realized prices, and an increase of 3.3% in production volumes. Production taxes for the nine months ended September 30, 2008 were reduced by $1.0 million as a result of refunds received on tax exempt wells identified by outside consultants.

Depreciation, depletion and amortization (“DD&A”) – Increase of $10.5 million was primarily due to an increase in DD&A on oil and natural gas properties of $9.2 million. For oil and natural gas properties, $2.2 million of the increase was due to higher production volumes and $7.0 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate on oil and natural gas properties per equivalent unit of production increased $0.23 to $2.15 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses –Increase of $3.0 million was due to primarily to higher compensation costs caused by our heightened level of activity. G&A expense is net of $9.8 million during the first three quarters of 2008 and $8.0 million in the same period of 2007 capitalized as part of our exploration and development activities.

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Interest Expense. Interest expense decreased during the first nine months of 2008 by $0.7 million, or 1.1%, compared to the same period in 2007 primarily as a result of lower interest rates paid, somewhat offset by increased levels of borrowings. The following table presents interest expense for the nine months ended September 30, 2007 and 2008:

	Nine Months Ended September 30,
	2007		2008
	(dollars in thousands)
Revolver interest	$	20,280	$	17,405
8 1/2% Senior Notes, due 2015		21,208		21,255
8 7/8% Senior Notes, due 2017		20,702		22,187
Bank fees and other interest		2,831		3,435
	$	65,021	$	64,282

Non-hedge derivative gains (losses).Non-hedge derivative gains were $10.0 million during the nine months ended September 30, 2008 and are comprised of losses of $24.6 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, gains of $29.2 million on collars that were not designated as hedges, and gains of $5.4 million related to natural gas basis differential swaps. Non-hedge derivative losses were $6.2 million during the nine months ended September 30, 2007 and are comprised of losses of $7.4 million on derivative contracts that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges, partially offset by net gains of $1.2 million related to natural gas basis differential swaps.

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, depreciation, and general and administrative expenses. We recognized $25.9 million in service company revenue including sales of $0.6 million to Edge, during the nine months ended September 30, 2008 with corresponding service company expense of $24.2 million, for a net profit of $1.7 million. We recognized $13.4 million in service company revenue during the nine months ended September 30, 2007 with corresponding service company expense of $11.8 million, for a net profit of $1.6 million. There were no service company revenues or expenses during the first quarter of 2007.

Loss on impairment of ethanol plant. We own 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. 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 $2.9 million, which was the amount of our investment in the ethanol plant through September 30, 2008.

Liquidity and capital resources

Crude oil and natural gas prices have fallen significantly since their third quarter 2008 levels. 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.

Our primary sources of liquidity are cash generated from our operations, our revolving credit line, and issuance of equity. At September 30, 2008, we had approximately $7.5 million of cash and cash equivalents and $61.2 million of availability under our revolving credit line with a borrowing base of $600.0 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit or other available debt sources 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 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 potential impact on our ability to utilize our revolving credit in 2009, we may change our cash management activities to draw down under our revolving credit line to maintain larger cash and cash equivalent balances. We expect to invest any significant cash balances in U. S. government securities and other highly liquid investments.

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Availability under our Credit Agreement is subject to a borrowing base which is set by our banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. Effective May 14, 2008 the borrowing base was adjusted to $600.0 million. We have agreed with the banks to delay the borrowing base redetermination scheduled for November 1, 2008, until December 10, 2008. If the banks do not agree to an increase in our borrowing base on December 10, 2008, we will be limited to the remaining availability under our existing borrowing base and cash available from operations to fund our operations and capital expenditures until the next redetermination date in 2009. As shown below, cash flows provided by financing activities were approximately $96.4 million during the nine months ended September 30, 2008 to fund our operations, and we expect to borrow an additional $40.0 million in the fourth quarter of 2008.

We continually evaluate our capital needs and compare them to our capital resources. We have reduced our level of capital expenditures for November and December of this year compared to the third quarter. We increased our 2008 capital expenditure budget due primarily to increased cash flow from higher commodity prices. We expect to fund our 2008 exploration and development expenditures from internally generated cash flow, cash on hand, and borrowings under our Credit Agreement. 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. Although we have not yet formally determined our 2009 exploration and development budget, if we are unable to consummate the merger with Edge, we expect to set this budget at an amount that approximates estimated discretionary cash flow generated during 2009.

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. If the commodity prices for crude oil and natural gas at year end are similar to current prices, we may be unable to borrow additional amounts under our Credit Agreement, regardless of the availability under our revolver.

We pledge our producing oil and natural 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 natural 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 natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural 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 natural gas prices through the use of commodity derivatives.

The net increase (decrease) in cash is summarized as follows:

	Nine Months Ended September 30,
(dollars in thousands)	2007			2008
Cash flows provided by operating activities	$	79,344		$	146,093
Cash flows used in investing activities		(183,735	)		(246,664	)
Cash flows provided by financing activities		110,609			96,424
Net increase (decrease) in cash during the period	$	6,218		$	(4,147	)

Sources and uses of cash. 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 nine months ended September 30, 2008, net cash provided from operations increased 84.1% from the same period in the prior year and provided approximately 59.2% of our net cash outflows used in investing activities. The increase is due primarily to an increase in oil and natural gas sales revenue, partially offset by higher operating expenses.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Cash flow from operating activities and debt financing were primarily used during the first nine months of 2008 to fund $224.0 million in cash expenditures for capital and exploration projects and property acquisitions.

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Our actual capital expenditures for oil and natural gas properties are detailed below:

(dollars in thousands)	Nine Months Ended September 30, 2008		Percent of Total
Development activities:
Developmental drilling	$	118,099	52.7	%
Enhancements		41,642	18.6	%
Tertiary recovery		16,547	7.4	%
Acquisitions:
Proved properties		38,481	17.2	%
Unproved properties		6,092	2.7	%
Exploration activities		3,176	1.4	%
Total	$	224,037	100.0	%

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $28.7 million for the acquisition and construction of new office and administrative facilities and equipment during the first nine months of 2008.

During the first nine months of 2008, we borrowed $90.0 million under our revolving credit facility.

As of September 30, 2008, we had cash and cash equivalents of $7.5 million and long-term debt obligations of $1.2 billion.

Our credit facility. As of September 30, 2008, we had $537.0 million outstanding under our Credit Agreement and the borrowing base was $600.0 million.

Our Credit Agreement requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2007 and September 30, 2008, our current ratio as computed using generally accepted accounting principles was 0.69 and 0.66, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.49 and 1.15, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

(dollars in thousands)	December 31, 2007			September 30, 2008
Current assets per GAAP	$	120,704		$	138,722
Plus—Availability under Credit Agreement		76,311			61,191
Less—Short-term derivative instruments		—			(6,302	)
Less—Deferred tax asset on hedges and asset retirement obligation		(19,123	)		(23,690	)
Current assets as adjusted	$	177,892		$	169,921
Current liabilities per GAAP	$	174,980		$	210,696
Less—Short-term derivative instruments		(54,307	)		(61,937	)
Less—Short-term asset retirement obligation		(1,000	)		(1,000	)
Current liabilities as adjusted	$	119,673		$	147,759
Current ratio for loan compliance		1.49			1.15

The remaining availability under the Credit Agreement is a significant factor in our ability to meet the Current Ratio requirement as defined in the Credit Agreement. If the banks do not increase our borrowing base prior to December 31, 2008, we may not meet the required Current Ratio at year end, which would constitute an event of default under our Credit Agreement.

Our Credit Agreement 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 banks may request a borrowing base redetermination once every six months. Effective May 14, 2008, the borrowing base was adjusted to $600.0 million. We have agreed with the banks to delay the borrowing base redetermination scheduled for November 1, 2008 until December 10, 2008. Interest is paid at least every three months on $447.0 million based upon LIBOR, as defined in the Credit

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Agreement as of December 31, 2007 (effective rate of 7.163%) and on $537.0 million based upon LIBOR as of September 30, 2008 (effective rate of 6.446%). The credit facility is collateralized by our oil and natural gas properties. The Credit Agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting.

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

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2008, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the Credit Agreement, plus a margin where the margin varies from 1.50% to 2.75% depending on the utilization percentage of the conforming borrowing base. At September 30, 2008, the LIBOR rate was 3.75%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 2.696%, resulting in an effective interest rate of 6.446% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

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

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

• incur additional indebtedness;

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

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

• make investments in or loans to others;

• change our line of business;

• enter into operating leases;

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

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

• enter into transactions with affiliates;

• issue preferred stock;

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

• enter into certain swap agreements; and

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

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

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

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

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

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• 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 purposes of the amended ratio, Consolidated Senior Total Debt consists of all outstanding loans under the Credit Agreement, letters of credit and all obligations under capital leases, as defined in the First Amendment to our Credit Agreement. The amended Credit Agreement requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

• 2.75 to 1.0 for the annualized periods commencing on January 1, 2007 and ending on the last day of the fiscal quarters 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 quarter thereafter.

We believe we were in compliance with all covenants under the Credit Agreement as of September 30, 2008.

The Credit Agreement also specifies events of default, including:

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

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

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

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

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

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

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

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

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

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

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

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.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties and from sales of equipment and materials through our service company, Green Country Supply. Crude oil and natural gas 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

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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. Service company sales are recorded in the month the product and services are delivered to the customer.

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 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 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 natural 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 No. 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 party to our revolving credit facility. We believe all of these institutions are acceptable credit risks.

Oil and natural gas properties.

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

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

• Future development and abandonment costs. Our future development cost include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. 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 of Accounting Standards No. 143,Accounting for Asset Retirement Obligations, we record a liability for the discounted fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

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

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

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

Also see the footnote disclosures included in Part 1, Item 1 of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in Part I, Item 1. Financial Statements, Note 1: Nature of operations and summary of significant accounting policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and natural 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 natural 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 natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in

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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 nine months ended September 30, 2008 production, our gross revenues from oil and natural gas sales would change approximately $1.5 million for each $0.10 change in natural gas prices and $2.8 million for each $1.00 change in oil prices.

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

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.

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

Our outstanding oil and natural gas derivative instruments as of September 30, 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)
4Q 2008	565	$	70.42	74	$	67.41	60	$	110.00 - 160.43	89.6	%
1Q 2009	510		70.42	111		67.15	60		110.00 - 164.28	90.1	%
2Q 2009	492		69.47	90		66.94	60		110.00 - 164.28	87.3	%
3Q 2009	480		68.81	90		66.57	60		110.00 - 164.28	90.7	%
4Q 2009	471		68.25	90		66.18	60		110.00 - 164.28	91.5	%
1Q 2010	420		67.40	102		65.80	60		110.00 - 168.55	87.8	%
2Q 2010	420		67.10	90		65.47	60		110.00 - 168.55	88.2	%
3Q 2010	408		66.43	90		65.10	60		110.00 - 168.55	88.3	%
4Q 2010	402		65.95	90		64.75	60		110.00 - 168.55	89.0	%
1Q 2011	309		64.40	99		64.24	51		110.00 - 152.71	77.0	%
2Q 2011	309		64.06	90		63.93	51		110.00 - 152.71	77.1	%
3Q 2011	309		63.71	90		63.61	51		110.00 - 152.71	78.9	%
4Q 2011	309		63.33	90		63.30	51		110.00 - 152.71	80.5	%
1Q 2012	281		124.66	—		—	157		100.00 - 135.25	80.5	%
2Q 2012	275		124.63	—		—	154		100.00 - 135.25	80.3	%
3Q 2012	271		124.61	—		—	152		100.00 - 135.25	80.6	%
4Q 2012	265		124.60	—		—	149		100.00 - 135.25	80.4	%
1Q 2013	262		124.44	—		—	110		100.00 - 133.50	74.0	%
2Q 2013	256		124.44	—		—	110		100.00 - 133.50	73.9	%
3Q 2013	250		124.45	—		—	107		100.00 - 133.50	73.1	%
4Q 2013	245		124.47	—		—	103		100.00 - 133.50	72.4	%
	7,509			1,196			1,786

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	Natural Gas Swaps			Natural Gas Collars			Percent of PDP production(1)
	Hedge			Non-hedge
	Volume MMBtu	Weighted average fixed price to be received		Volume MMBtu	Weighted average range to be received
4Q 2008	3,670	$	8.28	200	$	10.00 - $17.28	82.6	%
1Q 2009	1,650		9.14	990		10.00 -   13.85	59.5	%
2Q 2009	1,590		8.25	990		10.00 -   13.85	60.8	%
3Q 2009	1,590		8.41	990		10.00 -   13.85	64.9	%
4Q 2009	1,500		8.85	990		10.00 -   13.85	65.0	%
1Q 2010	450		9.80	840		10.00 -   11.53	35.0	%
2Q 2010	450		8.57	840		10.00 -   11.53	36.2	%
3Q 2010	450		8.74	840		10.00 -   11.53	37.3	%
4Q 2010	450		9.14	840		10.00 -   11.53	38.4	%
	11,800			7,520

	Natural Gas basis protection swaps
	Non-hedge
	Volume MMBtu	Weighted average fixed price to be paid
4Q 2008	2,120	$	0.90
1Q 2009	2,070		0.92
2Q 2009	540		0.82
	4,730

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

Subsequent to September 30, 2008, we entered into additional natural gas basis protection swaps for 1,040 MMBtu for the periods of December 2008 through October 2009 at a weighted average price of $0.91.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 30, 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, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $6.0 million.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation as of the end of the period covered by this quarterly report, our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Pursuant to the securities purchase agreement dated as of September 16, 2006, as amended, relating to the acquisition of Calumet, we recorded a receivable of approximately $14.4 million due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, we received a communication from the sellers disputing the calculation of the purchase price adjustment. We believe the value of the receivable was calculated in accordance with the securities purchase agreement and intend to diligently defend our position. Pretrial discovery is ongoing. 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. Written and documentary discovery is ongoing and depositions are underway. As of September 30, 2008, the recorded receivable was $14.4 million and was recorded in other assets on the consolidated balance sheet.

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

ITEM 1A. RISK FACTORS

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 have declined significantly over the past quarter 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 $60.00 per Bbl for crude oil and $6.00 per Mcf for natural gas, in both cases approximately a 55% decline from the earlier highs. As a result, our revenue from oil and gas sales are expected to decline significantly in the fourth quarter of this year as compared with the third quarter.

A continuing decline of oil and natural gas prices or a prolonged period of reduced oil and natural gas prices could result in a decrease in our exploration and development expenditures, which could negatively impact our future production.

We believe we currently have sufficient cash flows from operations and available amounts under our credit facility to meet our capital expenditure needs for the remainder of 2008. However, if oil and natural gas prices continue to decline or remain at reduced levels for a prolonged period of time, we may be unable to continue to fund capital expenditures at historical levels due to the decreased cash flows that will result from such reduced oil and natural gas prices. Additionally, a continuing decline in oil and natural gas prices or a prolonged period of lower oil and natural gas prices could result in a reduction of our borrowing base under our current credit facility, which will further reduce the availability of cash to fund our operations. As a result, we may have to reduce our capital expenditures in future years as compared to our capital expenditures in 2008 and recent years. A decrease in our capital expenditures will likely result in a slow down in the rate of growth of our production and could possibly result in a decrease in our production levels.

The current deterioration in the financial and credit markets may expose us to counterparty risk with respect to our sales of oil and natural gas and our derivative instruments.

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 generally hedge a substantial, but varying, portion of our anticipated oil and natural gas production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between the physical commodity being hedged and the price of the futures contract used for hedging. We use hedging to reduce our exposure to fluctuations in natural gas and oil prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage return on some of our acquisitions and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our

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derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. For a further discussion of our hedging activities, see the information under the caption “Oil and Natural Gas Prices” in Part I, Item 3 of this report and the discussion and tables in Note 2, “Derivative Financial Instruments,” to our consolidated financial statements appearing earlier in this report.

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.

If oil and gas prices decrease, we may be required to take write downs.

We may be required to write down the carrying value of our oil and gas properties when oil and gas prices decrease or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs or deterioration in our exploration results. Once recorded, a write down of oil and gas properties is not reversible at a later date even if oil and gas prices increase.

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

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2007, and under the heading “Risk Factors” in our prospectus included in our Registration Statement on Form S-4 declared effective on September 9, 2008, which could materially affect our business, financial condition, or future results.

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

On July 14, 2008, the holders of all the outstanding capital stock of Chaparral Energy, Inc. did adopt and consent to the following resolutions:

• The Merger and Agreement and Plan of Merger between Chaparral Exploration, LLC, a wholly owned entity of the Company, and Edge Petroleum Corporation and all related transactions with respect thereto are approved, adopted, ratified and confirmed in all respects.

• The Certificate of Incorporate of the Company shall be amended and restated in its entirety in substantially the form of Amended and Restated Certificate of Incorporate presented to and reviewed by the Stockholders.

• The First Amendment to Stockholders’ Agreement (the “First Amendment”) is approved, and the transactions contemplated by the First Amendment and the officers of the Company are hereby authorized and directed to execute and deliver the First Amendment on behalf of the Company.

• Any action taken by any director, officer, employee, or agent of the Company in connection with each of the transactions incidental to the Merger or any other transaction described and contemplated herein prior to the adoption of these resolutions are hereby ratified, confirmed, and approved.

ITEM 6. EXHIBITS

Exhibit No.	Description
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

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SIGNATURES

Pursuant to the requirements 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
	(Principal Executive Officer)
By:	/s/ Joseph O. Evans
Name:	Joseph O. Evans
Title:	Chief Financial Officer and Executive Vice President
	(Principal Financial Officer and Principal Accounting Officer)
Date: November 13, 2008

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EXHIBIT INDEX

Exhibit No.	Description
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

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