Chaparral Energy (CHAP) 10-Q 2007 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, 2007

OR

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

For the transition period from            to            

Commission file number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

Delaware	73-1590941
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

701 Cedar Lake Boulevard Oklahoma City, Oklahoma	73114
(Address of principal executive offices)	(Zip code)

(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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act). (Check one)

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

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

877,000 shares of the registrant’s Common Stock were outstanding as of November 12, 2007.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	5
Consolidated Statements of Operations for the three months and nine months ended September 30, 2007 and 2006	6
Consolidated Statements of Cash Flows for the nine months ended September 30, 2007 and 2006	7
Notes to Consolidated Financial Statements	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operation	18
Overview	18
Results of Operations	20
Liquidity and Capital Resources	24
Critical Accounting Policies and Estimates	29
Recent Accounting Pronouncements	31
Item 3. Quantitative and Qualitative Disclosures About Market Risk	31
Item 4. Controls and Procedures	32
Part II. OTHER INFORMATION	33
Item 1. Legal Proceedings	33
Item 1A. Risk Factors	33
Item 6. Exhibits	34
Signatures	36
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)

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, management’s plans, strategies, goals and objectives for future operations and growth.

These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of our senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements.

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

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

• the amount, nature and timing of capital expenditures;

• drilling of wells;

• competition and government regulations;

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

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

• increases in proved reserves;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• estimates of proved reserves;

• exploitation or property acquisitions;

• marketing of oil and natural gas; and

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

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

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GLOSSARY OF 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 oil or other liquid hydrocarbons.

• Bcfe. One billion cubic feet of natural gas equivalents.

• MBbl.One thousand Bbls.

• Mcf.One thousand cubic feet of natural gas.

• Mcfe.One thousand cubic feet of natural gas equivalents.

• MMBbl.One million Bbls.

• 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.

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

(Dollars in thousands, except share data)	December 31, 2006			September 30, 2007 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	8,803		$	15,021
Accounts receivable, net		62,728			75,831
Inventories		7,505			21,336
Deferred income taxes		968			5,809
Prepaid expenses		4,260			3,339
Derivative instruments		7,599			—
Total current assets		91,863			121,336
Property and equipment—at cost, net		31,809			46,240
Oil & gas properties, using the full cost method:
Proved		1,254,230			1,411,137
Unproved		18,299			26,607
Accumulated depletion and depreciation		(121,859	)		(179,987	)
Total oil & gas properties		1,150,670			1,257,757
Funds held in escrow		23,385			7,136
Other assets		33,708			39,740
	$	1,331,435		$	1,472,209
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	71,075		$	82,620
Revenue distribution payable		17,249			17,229
Current maturities of long-term debt and capital leases		3,555			5,393
Derivative instruments		12,376			17,728
Total current liabilities		104,255			122,970
Long-term debt and capital leases, less current maturities		647,717			442,491
Senior notes, net		325,000			647,447
Derivative instruments		2,300			31,551
Deferred compensation		771			2,163
Asset retirement obligations		27,377			29,299
Deferred income taxes		46,151			38,364
Commitments and contingencies (note 10)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2006 and September 30, 2007		9			9
Additional paid in capital		100,918			100,918
Retained earnings		80,883			82,172
Accumulated other comprehensive loss, net of taxes		(3,946	)		(25,175	)
		177,864			157,924
	$	1,331,435		$	1,472,209

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

(Dollars in thousands, except share and per share data)	Three months ended September 30,						Nine months ended September 30,
	2006 (unaudited)			2007 (unaudited)			2006 (unaudited)			2007 (unaudited)
Revenues:
Oil and gas sales	$	59,628		$	98,565		$	181,892		$	256,873
Gain (loss) from oil and gas hedging activities		1,267			(4,284	)		(5,412	)		(10,784	)
Service company sales		—			7,505			—			13,419
Total revenues		60,895			101,786			176,480			259,508
Costs and expenses:
Lease operating		15,719			27,033			46,951			77,835
Production tax		4,324			6,803			13,869			18,265
Depreciation, depletion and amortization		11,967			22,364			35,163			63,385
General and administrative		3,005			5,727			9,660			15,911
Service company expenses		—			6,564			—			11,626
Total costs and expenses		35,015			68,491			105,643			187,022
Operating income		25,880			33,295			70,837			72,486
Non-operating income (expense):
Interest expense		(10,335	)		(22,728	)		(28,993	)		(65,021	)
Non-hedge derivative losses		(4,522	)		(2,399	)		(4,634	)		(6,228	)
Other income		30			348			556			815
Net non-operating expense		(14,827	)		(24,779	)		(33,071	)		(70,434	)
Income from before income taxes and minority interest		11,053			8,516			37,766			2,052
Income tax expense		4,241			3,254			14,520			764
Minority interest		—			—			(71	)		—
Net income	$	6,812		$	5,262		$	23,317		$	1,288
Earnings per share
Net income per share (basic and diluted)	$	8.76		$	6.00		$	30.06		$	1.47
Weighted average number of shares used in calculation of basic and diluted earnings per share		777,217			877,000			775,747			877,000

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

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

(Dollars in thousands)	Nine months ended September 30,
	2006 (unaudited)			2007 (unaudited)
Cash flows from operating activities
Net income	$	23,317		$	1,288
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		35,163			63,385
Deferred income taxes		14,520			764
Unrealized (gain) loss on ineffective portion of hedges		(17,566	)		3,126
Non-cash change in fair value of derivative instruments		4,634			6,228
Other		597			799
Change in assets and liabilities
Accounts receivable		(2,701	)		(5,793	)
Inventories		(1,279	)		1,849
Prepaid expenses and other assets		25			619
Accounts payable and accrued liabilities		9,160			6,171
Revenue distribution payable		6,163			(21	)
Deferred compensation		127			1,392
Net cash provided by operating activities		72,160			79,807
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(160,782	)		(162,935	)
Acquisition of businesses including funds released from escrow, net of cash acquired		—			(37,275	)
Proceeds from dispositions of property and equipment and oil and gas properties		5,557			298
Purchase of prepaid production tax asset		(5,000	)		—
Cash in escrow		—			16,382
Other		(4,986	)		(668	)
Net cash used in investing activities		(165,211	)		(184,198	)
Cash flows from financing activities
Proceeds from long-term debt		95,805			99,879
Repayment of long-term debt		(1,929	)		(303,159	)
Proceeds from long-term bonds		—			322,329
Proceeds from equity issuance		102,000			—
Principal payments under capital lease obligations		(106	)		(129	)
Dividends		(1,050	)		—
Settlement of derivative instruments acquired		—			(1,106	)
Fees paid related to financing activities		(542	)		(7,205	)
Net cash provided by financing activities		194,178			110,609
Net increase in cash and cash equivalents		101,127			6,218
Cash and cash equivalents at beginning of period		1,598			8,803
Cash and cash equivalents at end of period	$	102,725		$	15,021
Supplemental cash flow information
Cash paid during the period for:
Interest	$	22,068		$	47,088

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

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Supplemental disclosure of non-cash investing and financing activities

During the nine months ended September 30, 2007, the Company entered into a capital lease obligation of $21 for the purchase of machinery and equipment and recorded non-cash additions to oil and gas properties of $1,113.

During the nine months ended September 30, 2006 and 2007, the Company recorded an asset and related liability of $1,340 and $209, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $669 was capitalized during the nine months ended September 30, 2006 primarily related to the acquisition of unproved oil and gas leaseholds. During the nine months ended September 30, 2007, interest of $1,180 and $32 was capitalized related to the acquisition of unproved oil and gas leaseholds and the construction of the Company’s office building, respectively.

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Chaparral Energy, Inc. and subsidiaries

Notes to Consolidated Financial Statements

(dollars in thousands, unless otherwise noted)

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

Chaparral Energy, Inc. and subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) is involved in the acquisition, exploration, development, production and operation of oil and gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, Montana and Wyoming. Beginning in April 2007, the Company expanded its operations to include oil and gas services through the acquisition of Green Country Supply, Inc. (“GCS”). GCS provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas, 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, 2007 and for the three months and nine months ended September 30, 2006 and 2007 is unaudited. In the opinion of management, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three and nine months ended September 30, 2007 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2007.

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 April 2, 2007.

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.

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.

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.

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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, 2006 and September 30, 2007 consist of the following:

	December 31, 2006		September 30, 2007
Equipment inventory	$	4,832	$	4,330
Oil and gas product		2,673		2,922
Service company inventory for resale		—		14,084
	$	7,505	$	21,336

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, 2006		September 30, 2007
Title defect escrow from acquisition	$	21,795	$	379
Plugging and abandonment escrow		1,590		1,622
Post closing adjustment escrow from acquisition		—		5,135
	$	23,385	$	7,136

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.

Income Taxes

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

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption, we recognized no material adjustment in our tax liability for unrecognized income tax benefits. At the adoption date of January 1, 2007, we had approximately $100 of unrecognized tax benefits, all of which would affect our effective tax rate if recognized. At September 30, 2007, the unrecognized tax benefit amount was unchanged from adoption.

If applicable, we would recognize interest and penalties related to uncertain tax positions in interest expense. As of September 30, 2007, we have not accrued interest related to uncertain tax positions due to overpayments.

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

Recently Issued Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and

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establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company will adopt SFAS No. 157 as of January 1, 2008 and is currently evaluating the impact, if any, that SFAS No. 157 will have on its consolidated financial statements.

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” which provides entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This Statement is effective as of the beginning of the first fiscal year that begins after November 15, 2007. The Company will adopt SFAS No. 159 as of January 1, 2008 and is currently evaluating the impact, if any, that SFAS No. 159 will have on its consolidated financial statements.

Note 2: Acquisition of Green Country Supply, Inc.

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

At the closing date of the sale, the Company withheld and deposited into escrow $5,029 of the purchase price for certain working capital, environmental and employment adjustments. Pursuant to the agreement, upon settlement of the various requirements, the amount in escrow will be disbursed. If the requirements are not met, the amount escrowed will be returned to the Company. As of September 30, 2007, the entire amount remained in escrow.

The unaudited pro forma information of the Company set forth below includes the operations of GCS for the nine months ended September 30, 2007 as if the acquisition occurred on January 1, 2007. The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined.

(dollars in thousands, except per share data)	Nine months ended September 30, 2007
	As reported		Pro forma
Revenue	$	259,508	$	267,865
Net income	$	1,288	$	1,529
Net income per share (basic and diluted)	$	1.47	$	1.74

Note 3: Derivative Financial Instruments

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

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

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As part of the Calumet acquisition, the Company assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. In accordance with SFAS 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. Fair value is generally determined based on the difference between the fixed contract price and the underlying forward market price at the determination date considering the time value of money.

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

	December 31, 2006			September 30, 2007
Derivative assets (liabilities):
Gas swaps	$	10,118		$	6,643
Oil swaps		(16,349	)		(56,945	)
Natural gas basis differential swaps		(846	)		1,023
	$	(7,077	)	$	(49,279	)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2007			2006			2007
Reclassification of settled contracts	$	(6,244	)	$	(5,286	)	$	(22,978	)	$	(7,658	)
Gain (loss) on ineffective portion of derivatives qualifying for hedge accounting		7,511			1,002			17,566			(3,126	)
	$	1,267		$	(4,284	)	$	(5,412	)	$	(10,784	)

Based upon market prices at September 30, 2007, the Company expects to charge $10,488 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, 2007 are expected to be settled by December 2011.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2007			2006			2007
Unrealized loss on non-qualified derivative contracts	$	(2,665	)	$	(1,620	)	$	(2,665	)	$	(7,430	)
Unrealized gain (loss) on natural gas basis differential contracts		(1,857	)		(530	)		(1,969	)		1,870
Loss on settlement of natural gas basis differential contracts		—			(249	)		—			(668	)
	$	(4,522	)	$	(2,399	)	$	(4,634	)	$	(6,228	)

Hedge settlement payments of $3,444 and $5,345 were included in accounts payable and accrued liabilities at December 31, 2006 and September 30, 2007, respectively. Hedge settlement receivables of $759 and $648 were included in accounts receivable at December 31, 2006 and September 30, 2007, respectively.

Note 4: Asset Retirement Obligation

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, 2007:

	Nine Months Ended September 30, 2007
Beginning balance	$	28,126
Liabilities incurred in current period		209
Liabilities settled in current period		(80	)
Accretion expense		1,793
	$	30,048
Less current portion		749
	$	29,299

Note 5: Long-term debt

Long-term debt at December 31, 2006 and September 30, 2007 consisted of the following:

	December 31, 2006		September 30, 2007
Revolving credit line with banks (1)	$	637,000	$	430,000
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 6.53% to 7.98%, due June 2008 through September 2021; collateralized by real property		7,036		8,278
Installment notes payable, principal and interest payable quarterly in varying amounts, non-interest bearing (discounted at 5.6% at December 31, 2006 and September 30, 2007, respectively), due September and December 2007		837		111
Non-interest bearing forgivable government loan (2)		250		—
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.62% to 9.387%, due July 2007 through September 2012; collateralized by automobiles, machinery and equipment		5,821		9,275
		650,944		447,664
Less current maturities		3,392		5,218
	$	647,552	$	442,446

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(1) In October 2006, the Company entered into a Seventh Restated Credit Agreement, which provides for a $500,000 maximum commitment amount and is scheduled to mature on October 31, 2010. Interest is paid at least every three months on $634,000 based upon LIBOR and $3,000 based on an Alternative Base Rate, as defined in the credit agreement, as of December 31, 2006 (effective rate of 7.375% and 8.750%, respectively) and on $430,000 based upon LIBOR as of September 30, 2007 (effective rate of 7.356%). The credit line is collateralized by the Company’s oil and gas properties. The agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting.

As of March 31, 2007, the Company did not meet the 5.00 to 1.0 Consolidated Total Debt to Consolidated EBITDAX ratio as required by the Credit Agreement. Effective May 11, 2007, the Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For purposes of the amended ratio, Consolidated Senior Total Debt consists of all outstanding loans under the Credit Agreement, letters of credit and 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, 2007.

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

In April 2007, Oklahoma Ethanol decided to move the location of the planned ethanol plant from Enid, Oklahoma to Blackwell, Oklahoma. As a result of the relocation, the Company paid back the non-interest bearing loan of $250 received from the City of Enid.

Note 6: Senior Notes

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

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

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

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

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

• make investments;

• create liens on assets;

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

• transfer or sell assets;

• engage in transactions with affiliates;

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

• enter into other lines of business.

In connection with the issuance of our 8 ⁷/8% Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the Securities and Exchange Commission related to

14

an offer to exchange the notes for other freely tradable notes and complete such exchange offer within 270 days of the issue date. If we fail to complete the exchange offer within 270 days after the issue date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

During September 2007, the Company determined that the exchange offer would not be completed within the 270 day window as required by the registration rights agreement. As a result, the Company accrued liquidated damages of $0.2 million during the three months ended September 30, 2007.

Chaparral is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries, excluding Pointe Vista Development, L.L.C. (“Pointe Vista”). Pointe Vista, a 100% owned subsidiary and Oklahoma Ethanol, a 66.67% owned subsidiary, have no significant operations or capitalization and are not restricted subsidiaries or guarantors of the notes.

Senior Notes at December 31, 2006 and September 30, 2007 consisted of the following:

	December 31, 2006		September 30, 2007
8.5% Senior Notes due 2015	$	325,000	$	325,000
8.875% Senior Notes due 2017		—		325,000
Discount on Senior Notes		—		(2,553	)
	$	325,000	$	647,447

Based on market prices, at September 30, 2007, the fair value of the 8.5% Senior Notes and 8.875% Senior Notes were $303,875 and $303,875, respectively.

In connection with the issuance of the Senior Notes, the Company recorded a discount of $2,671 and capitalized $16,439 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. The Company had unamortized issuance costs of $14,989 as of September 30, 2007 that are included in other assets. Amortization of $42 and $281 was charged to interest expense during the three months ended September 30, 2007 related to the discount and issuance costs, respectively. Amortization of $118 and $803 was charged to interest expense during the nine months ended September 30, 2007 related to the discount and issuance costs, respectively.

Note 7: Related Party Transactions

In September 2006, Chesapeake Energy Corporation (“Chesapeake”) acquired a 31.9% beneficial interest in the Company through the sale of common stock. The Company participates in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings of $2,483 and $964, respectively for the three months ended September 30, 2007 and $5,863 and $3,289, respectively for the nine months ended September 30, 2007 on these properties. In addition, Chesapeake participates in ownership of properties operated by the Company. During the three months ended September 30, 2007, the Company paid revenues and recorded joint interest billings of $393 and $518, respectively to Chesapeake. During the nine months ended September 30, 2007, the Company paid revenues and recorded joint interest billings of $1,090 and $904, respectively. There were no significant amounts receivable or payable to Chesapeake at September 30, 2007.

Note 8: Deferred Compensation

Effective January 1, 2004, the Company implemented a Phantom Unit Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom units may be awarded to participants in total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Under the original plan, phantom units vest on the seventh anniversary of the award date of the phantom unit, but may also vest on a pro-rata basis following a participant’s termination of employment with the Company due to death, disability, retirement or termination by the Company without cause. Also, phantom units vest if a change of control event occurs. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Payment is not required by the participant upon redemption. Effective January 1, 2007 the Company reduced the phantom unit vest period from the seventh anniversary of the award date to the fifth anniversary of the 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 recognized deferred compensation gain of $30 resulting in an increase in net income and expense of $702 resulting in a reduction in net income for the three months ended September 30, 2006 and 2007, respectively. The Company recognized deferred compensation expense of $130 and $1,392 resulting in a reduction in net income for the nine months ended September 30, 2006 and 2007, respectively.

15

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

	Fair Value		Phantom Units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per unit)
Unvested and total outstanding at December 31, 2006	$	14.29	160,038
Granted	$	14.29	47,643
Vested	$	14.29	—
Forfeited	$	14.29	(5,599	)
Unvested and total outstanding at September 30, 2007	$	19.29	202,082		2.37	$	3,898

Upon vesting, the Company is required to redeem all units. Accordingly, the contract term and the vesting period are the same. There are no vested units as of September 30, 2007.

The fair value of each unit 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, 2007 are as follows:

Dividend yield	0.0	%
Volatility	75.0	%
Risk-free interest rate	4.23	%
Expected life (in years)	1.25-4.75

The Company estimated volatility based on an average of the volatilities of similar public entities whose share prices are publicly available over the expected life of the granted units. The risk-free interest rate is based on the U.S. Treasury yield curve for the expected remaining term of the unit. 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 unit.

As of September 30, 2007, there was approximately $1,735 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 2.37 years.

Note 9: 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, therefore, no segment information is provided for the three and nine months ended September 30, 2006.

	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 (loss) before income taxes	$	7,480	$	1,319			(283	)	$	8,516
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 (loss) before income taxes	$	111	$	2,439			(498	)	$	2,052
As of September 30, 2007:
Total Assets	$	1,450,724	$	25,721		$	(4,236	)	$	1,472,209

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Note 10: 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 $865 and $1,675 as of December 31, 2006 and September 30, 2007, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 7.36% at September 30, 2007) 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, 2006 and 2007.

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

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, the Company recorded a receivable of $14,406 due from the sellers related to the post-closing purchase price adjustment for working capital. On August 9, 2007, the Company received a communication from the sellers disputing the calculation of the purchase price adjustment. The Company believes the receivable was calculated in accordance with the securities purchase agreement and intends to diligently defend its position. On September 13, 2007, the Company filed a petition in the District Court of Tulsa County, State of Oklahoma, against John Milton Graves Trust u/t/a 6/11/2004, et al, seeking a declaratory judgement confirming this position. As of September 30, 2007, the recorded receivable was $14,406, of which $9,793 is in dispute, and was recorded in accounts receivable on the consolidated balance sheet.

Note 11: Capital Stock

On September 27, 2006, the Company effected a 775-for-1 stock split in the form of a stock dividend to shareholders of record as of September 26, 2006. As a result of the split, 774,000 additional shares were issued and retained earnings were reduced by $7. All share and per share amounts discussed and disclosed in this Quarterly Report on Form 10-Q reflect the effect of this stock split.

Cash dividends of $350 and $1,050 were paid during the three and nine months ended September 30, 2006 respectively. No dividends were paid during the three and nine months ended September 30, 2007.

Note 12: Comprehensive Income

Components of comprehensive income (loss), net of related tax, are as follows for the three and nine months ended September 30, 2006 and 2007:

	Three months ended September 30,					Nine months ended September 30,
	2006		2007			2006		2007
Net income (loss)	$	6,812	$	5,262		$	23,317	$	1,288
Unrealized gain (loss) on hedges		16,859		(6,905	)		25,451		(25,745	)
Reclassification adjustment for hedge losses included in net income (loss)		3,832		3,060			14,104		4,516
Comprehensive income (loss)	$	27,503	$	1,417		$	62,872	$	(19,941	)

Note 13: Subsequent Event

Effective November 1, 2007, the borrowing base on the Company’s revolving line of credit was increased to $525.0 million. Under the agreement the Company has committed to hedging 80% of its internally estimated PDP crude oil production for 2008, 2009 and 2010 and 75% and 25% of its internally estimated PDP natural gas production for 2008 and 2009, respectively.

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

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 April 2, 2007.

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 and our Annual Report on Form 10-K for the year ended December 31, 2006.

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 enhanced oil recovery projects. Beginning in April 2007, we expanded our operations to include oil and gas services through the acquisition of Green Country Supply, Inc. (“GCS”). GCS provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

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

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and natural gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. See “Quantitative and Qualitative Disclosures 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 14.3%, 11.0% and 8.6% during 2007, 2008 and 2009, respectively. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

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

• the quantity of our proved oil and gas reserves;

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

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

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

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During the third quarter of 2007, we had a record quarterly production of 10,609 MMcfe, a 39.5% increase over production levels in the third quarter of 2006, primarily as a direct result of the properties acquired in the Calumet acquisition. Higher operating costs and increased interest expense resulting from the issuance of our 8 ⁷/8% Senior Notes slightly offset the revenue impact of higher production and prices, causing a 27% decrease in net income (loss) between the comparable third quarters. The net result was income of $5.3 million in the third quarter of 2007 as compared to net income of $6.8 million during the same period in 2006.

All of our expenses increased on both an absolute and per Mcfe basis during the third quarter of 2007 compared to the comparable period in 2006 due to (i) higher overall industry costs, (ii) additional costs associated with the properties acquired in the Calumet acquisition, and (iii) higher compensation expense resulting from additional employees and increased salaries and benefits which we consider necessary in order to remain competitive in the industry.

We have established a $212.0 million oil and gas property capital expenditure budget for 2007. From January 1, 2007 through September 30, 2007, we spent $122.9 million on exploratory and development activities and approximately $42.9 million on acquisitions of oil and gas properties, including $17.6 million disbursed from escrow related to title defects on the Calumet acquisition.

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:

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

• Acquisition of Calumet Oil Company and affiliates. On October 31, 2006, we acquired all of the outstanding stock of Calumet Oil Company and all of the limited partnership interests and membership interests of certain of its affiliates for a cash purchase price of $500.0 million. Calumet owns properties principally located in Oklahoma and Texas, areas which are complementary to our core areas of operations. Calumet’s proved reserves are long-lived, have low production decline rates and are approximately 97% oil. In addition to increasing our current average net daily production, many of the properties have significant drilling and enhanced oil recovery opportunities. Additionally, as part of the transaction, we acquired Calumet’s hedging arrangements, which included hedge swaps of 75 MBbls per month at $63.00 during 2007 and 30 MBbls per month at $68.10 during 2008.

• 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 will be accounted for as a production tax benefit asset and will be netted against tax credits realized in other income using the effective yield method over the expected recovery period. During the nine months ended September 30, 2007, we recognized $0.2 million of income associated with the tax credits.

• Oklahoma Ethanol.In August 2005, we entered a joint venture, Oklahoma Ethanol, L.L.C., to construct and operate an ethanol production plant in Oklahoma. We spent approximately $1.4 million toward the design for the construction of the plant in the nine months ended September 30, 2007.

• Green Country Supply Acquisition.On April 16, 2007, we closed on the purchase of all of the outstanding shares of stock of Green Country Supply, Inc. (“GCS”) for an aggregate purchase price of $25.0 million, subject to certain post closing price adjustments. Approximately $5.0 million of the purchase price was deposited into escrow as security for certain potential working capital, environmental and employment adjustments. GCS was acquired from the former shareholders of Calumet Oil Company and provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps and related services to oil and gas operators primarily in Oklahoma, Texas and Wyoming.

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

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Results of Operations

Comparison of Three Months ended September 30, 2007 to Three Months ended September 30, 2006.

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

	Three Months Ended September 30,				Percentage Change
	2006		2007
Oil and gas sales (dollars in thousands)
Oil	$	27,533	$	67,577	145.4	%
Gas		32,095		30,988	(3.4	)%
Total	$	59,628	$	98,565	65.3	%
Production
Oil (MBbls)		416		926	122.6	%
Gas (MMcf)		5,109		5,053	(1.1	)%
MMcfe		7,605		10,609	39.5	%
Average sales prices (excluding hedging)
Oil per Bbl	$	66.19	$	72.98	10.3	%
Gas per Mcf		6.28		6.13	(2.4	)%
Mcfe		7.84		9.29	18.5	%

Oil sales increased 145.4% from $27.5 million during the three months ended September 30, 2006 to $67.6 million during the same period in 2007. This increase was due to a 122.6% increase in production volumes to 926 MBbls, and a 10.3% increase in average oil prices to $72.98 per barrel. Natural gas sales revenues decreased 3.4% from $32.1 million during the three months ended September 30, 2006 to $31.0 million during the same period in 2007. This decrease was due to a 2.4% decrease in average gas prices and a 1.1% decrease in production volumes to 5,053 MMcf. Oil production for the three months ended September 30, 2007 increased primarily due to the addition of volumes from the Calumet acquisition, our drilling program and enhancements of our existing properties. Approximately 426 MBbls of the oil production for the three months ended September 30, 2007 was related to properties acquired in the Calumet acquisition.

Production volumes by area were as follows (MMcfe):

	Three Months Ended September 30,		Percentage Change
	2006(1)	2007
Mid Continent	4,473	7,023	57.0	%
Permian	1,271	1,586	24.8	%
Ark-La-Tex	447	475	6.3	%
North Texas	282	402	42.6	%
Rockies	326	246	(24.5	)%
Gulf Coast	806	877	8.8	%
Totals	7,605	10,609	39.5	%

(1) During the fourth quarter of 2006, we realigned the boundaries for our reportable areas. As a result, certain reclassifications were made to prior year amounts to conform to current year presentation.

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.

20

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,
	2006			2007
	(dollars in thousands)
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(6,244	)	$	(5,286	)
Hedge ineffectiveness		7,511			1,002
Total	$	1,267		$	(4,284	)

Our loss from oil and gas hedging activities in the third quarter of 2007 was primarily due to losses on hedge settlements resulting from increased oil prices. As a result of lower NYMEX forward strip gas prices at September 30, 2007 compared to June 30, 2007, hedge ineffectiveness resulted in a gain of $1.0 million compared to a gain of $7.5 million in the third quarter of 2006. The decreased ineffectiveness gain during the third quarter of 2007 as compared to the same period in 2006 is also a result of a significant decrease in the volumes of natural gas hedged as of September 30, 2007 compared to September 30, 2006.

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, 2006	$	66.19	$	50.41	76.2	%
Three months ended September 30, 2007		72.98		62.75	86.0	%
Gas (per Mcf):
Three months ended September 30, 2006	$	6.28	$	7.81	124.4	%
Three months ended September 30, 2007		6.13		7.16	116.8	%

Service company revenues and operating expenses.Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. We recognized $7.5 million in service company revenue in the current quarter with corresponding service company expense of $6.6 million, for a net profit of $0.9 million. There were no service company revenues or expenses during the third quarter of 2006.

Costs and Expenses. The following table presents information about our operating expenses for the third quarter of 2006 and 2007:

	Amount						Per Mcfe
	Three Months Ended September 30,				Percent Change		Three Months Ended September 30,				Percent Change
	2006		2007				2006		2007
	(dollars in thousands)
Lease operating expenses	$	15,719	$	27,033	72.0	%	$	2.07	$	2.55	23.2	%
Production taxes		4,324		6,803	57.3	%		0.57		0.64	12.3	%
Depreciation, depletion and amortization		11,967		22,364	86.9	%		1.57		2.11	34.4	%
General and administrative		3,005		5,727	90.6	%		0.40		0.54	35.0	%

Lease operating expenses – Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $6.4 million of the increase was attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor, and materials resulting from the sustained strength of commodity prices.

Production taxes (which include ad valorem taxes) – Increase was primarily due to a 18.5% increase in averaged realized prices, and an increase of 39.5% in production volumes compared to the same period in 2006.

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Depreciation, depletion and amortization (“DD&A”) – Increase was primarily due to increase in DD&A on oil and gas properties of $9.8 million. For oil and gas properties, $5.8 million of the increase was due to higher production volumes and $4.0 million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production increased $0.52 to $1.93 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses – Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. We also recognized deferred compensation expense of $0.7 million related to our Phantom Unit Plan in the third quarter of 2007 due to the continued strength of oil commodity prices. G&A expense also includes $0.1 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $2.8 million in the third quarter of 2007 and $2.1 million in the same period of 2006 capitalized as part of our exploration and development activities.

Interest Expense. Interest expense increased during the third quarter of 2007 by $12.4 million, or 119.9%, compared to the same period in 2006 primarily as a result of increased levels of borrowings, including the issuance of our 8 ⁷/8% Senior Notes due 2017, and higher interest rates. Approximately $11.1 million of the increase is due to our increased levels of borrowings and $1.3 million is due to higher interest rates.

Non-hedge derivative losses. 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. Non-hedge derivative losses were $4.5 million during the three months ended September 30, 2006 and are comprised of losses of $1.8 million on natural gas basis differential swaps and $2.7 million on non-qualified derivative contracts.

Comparison of Nine Months ended September 30, 2007 to Nine Months ended September 30, 2006.

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

	Nine Months Ended September 30,				Percentage Change
	2006		2007
Oil and gas sales (dollars in thousands)
Oil	$	80,462	$	160,059	98.9	%
Gas		101,430		96,814	(4.6	)%
Total	$	181,892	$	256,873	41.2	%
Production
Oil (MBbls)		1,262		2,507	98.7	%
Gas (MMcf)		15,592		15,246	(2.2	)%
MMcfe		23,164		30,288	30.8	%
Average sales prices (excluding hedging)
Oil per Bbl	$	63.76	$	63.84	0.1	%
Gas per Mcf		6.51		6.35	(2.5	)%
Mcfe		7.85		8.48	8.0	%

Oil sales increased 98.9% from $80.5 million during the nine months ended September 30, 2006 to $160.1 million during the same period in 2007. This increase was due to a 98.7% increase in production volumes to 2,507 MBbls and a 0.1% increase in average oil prices to $63.84 per barrel. Natural gas sales revenues decreased 4.6% from $101.4 million during the nine months ended September 30, 2006 to $96.8 million during the same period in 2007. This decrease was due to a 2.2% decline in production volumes to 15,246 MMcf and a 2.5% decrease in average gas prices. Oil production for the nine months ended September 30, 2007 increased primarily due to the addition of volumes from the Calumet acquisition, 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 2007. Approximately 1,149 MBbls of the oil production for the nine months ended September 30, 2007 was related to properties acquired in the Calumet acquisition. Gas production for the nine months ended September 30, 2007 decreased primarily due to the recognition of a favorable settlement of a disputed ownership interest that resulted in the one-time recognition of 393 MMcf for production from May 2005 to April 2006 during the nine months ended September 30, 2006.

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Production volumes by area were as follows (MMcfe):

	Nine Months Ended September 30,		Percentage Change
	2006(1)	2007
Mid Continent	13,585	19,749	45.4	%
Permian	3,947	4,803	21.7	%
Ark-La-Tex	1,353	1,366	1.0	%
North Texas	829	1,045	26.1	%
Rockies	903	712	(21.2	)%
Gulf Coast	2,547	2,613	2.6	%
Totals	23,164	30,288	30.8	%

(1) During the fourth quarter of 2006, we realigned the boundaries for our reportable areas. As a result, certain reclassifications were made to prior year amounts to conform with current year presentation.

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:

	Nine Months Ended September 30,
	2006			2007
	(dollars in thousands)
Gain (loss) from oil and gas hedging activities:
Hedge settlements	$	(22,978	)	$	(7,658	)
Hedge ineffectiveness		17,566			(3,126	)
Total	$	(5,412	)	$	(10,784	)

Our loss from oil and gas hedging activities during the first nine months of 2007 was primarily due to losses on hedge settlements due to increased oil prices. As a result of higher NYMEX forward strip gas prices at September 30, 2007 compared to December 31, 2006, hedge ineffectiveness resulted in a loss of $3.1 million compared to a gain of $17.6 million during the same period in 2006. Settlements on our oil and gas contracts decreased $15.3 million primarily due to the settlement of higher overall hedge positions during the nine months ended September 30, 2007 as compared to the same period in 2006.

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, 2006	$	63.76	$	44.46	69.7	%
Nine months ended September 30, 2007		63.84		58.05	90.9	%
Gas (per Mcf):
Nine months ended September 30, 2006	$	6.51	$	7.72	118.6	%
Nine months ended September 30, 2007		6.35		6.60	103.9	%

Service company revenues and operating expenses.Service company revenues and expenses consist of third-party revenue and operating expenses of Green Country Supply, which was acquired during the second quarter of 2007. Revenues are generated through the sale of oilfield supplies, chemicals, downhole submersible pumps and related services. Operating expenses consist of costs of sales related to product sales and general and administrative expenses. The Company recognized $13.4 million in service company revenue during the second and third quarters with corresponding service company expense of $11.6 million, for a net profit of $1.8 million. There were no service company revenues or expenses during the first three quarters of 2006 or in the first quarter of 2007.

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Costs and Expenses. The following table presents information about our operating expenses for the first nine months of 2006 and 2007:

	Amount						Per Mcfe
	Nine Months Ended September 30,				Percent Change		Nine Months Ended September 30,				Percent Change
	2006		2007				2006		2007
(dollars in thousands)
Lease operating expenses	$	46,951	$	77,835	65.8	%	$	2.03	$	2.57	26.6	%
Production taxes		13,869		18,265	31.7	%		0.60		0.60	0.0	%
Depreciation, depletion and amortization		35,163		63,385	80.3	%		1.52		2.09	37.5	%
General and administrative		9,660		15,911	64.7	%		0.42		0.53	26.2	%

Lease operating expenses – Increase was primarily due to increases in the net number of producing wells and higher oilfield service costs, including costs associated with artificial lift on oil properties. Approximately $19.8 million of the increase were expenses attributable to the properties acquired in the Calumet acquisition. Per unit expenses were higher for all categories of lease operating expenses due to continued upward pressure on service costs, labor, and materials resulting from the sustained strength of commodity prices. Included in these figures are $5.4 million of costs associated with workovers in the first three quarters of 2007 compared to $6.0 million in the same period of 2006.

Production taxes (which include ad valorem taxes) – Increase was primarily due to 8.0% higher averaged realized prices, and an increase of 30.8% in production volumes compared to the same period in 2006.

Depreciation, depletion and amortization (“DD&A”) – Increase was primarily due to increase in DD&A on oil and gas properties of $26.4 million. For oil and gas properties, $13.7 million of the increase was due to higher production volumes and $12.8 million due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate on oil and gas properties per equivalent unit of production increased $0.55 to $1.92 per Mcfe primarily due to estimated higher future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses – Increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity, including the Calumet acquisition. In addition, we increased our compensation plan, including an increase in our officer bonus program and decreased the vesting period related to the phantom unit plan in efforts to meet market demand and recruit and maintain essential personnel. Approximately $0.4 million of the increase was due to the revision in the phantom unit plan. G&A expense also includes $0.4 million of expenses associated with Pointe Vista Development and Oklahoma Ethanol. G&A expense is net of $8.0 million during the first three quarters of 2007 and $6.3 million in the same period of 2006 capitalized as part of our exploration and development activities.

Interest Expense. Interest expense increased during the first nine months of 2007 by $36.0 million, or 124.3%, compared to the same period in 2006 primarily as a result of increased levels of borrowings including the issuance of our 8 ⁷/8% Senior Notes due 2017, and higher interest rates paid. Approximately $32.5 million of the increase is due to our increased levels of borrowings and $3.5 million is due to higher interest rates paid.

Non-hedge derivative losses. 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. Non-hedge derivative losses were $4.6 million during the nine months ended September 30, 2006 and are comprised of losses of $1.9 million on natural gas basis differential swaps and $2.7 million on non-qualified derivative contracts.

Liquidity and Capital Resources

Overview. Our primary needs for cash are for acquisition, exploration, development and production of oil and gas properties and the repayment of principal and interest on outstanding debt. We fund our exploration and development activities primarily through internally generated cash flows and debt financing. We adjust capital expenditures in response to changes in oil and natural gas prices, drilling results, availability of acquisition opportunities, equity funding and cash flow.

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We have historically utilized net cash provided by operating activities, available cash, sale of equity and debt as capital resources to obtain necessary funding for all other cash needs. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months.

The net increase in cash is summarized as follows:

	Nine Months Ended September 30,
(dollars in thousands)	2006			2007
Cash flows provided by operating activities	$	72,160		$	79,807
Cash flows used in investing activities		(165,211	)		(184,198	)
Cash flows provided by financing activities		194,178			110,609
Net increase in cash during the period	$	101,127		$	6,218

Sources and uses of cash. Substantially all of our cash flow from operating activities is from the production and sale of oil and gas, reduced or increased by associated hedging activities. For the nine months ended September 30, 2007, net cash provided from operations increased 10.6% from the same period in the prior year and provided approximately 43.3% of our net cash outflows used in investing activities. The increase is due primarily to an increase in oil and gas sales revenue, partially offset by higher operating and interest 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 2007 to fund $202.4 million in cash expenditures for capital and exploration projects and property acquisitions.

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

(dollars in thousands)	Nine Months Ended September 30, 2007		Percent of Total
Development activities:
Developmental drilling	$	66,121	39.9	%
Enhancements		37,227	22.4	%
Tertiary recovery		10,291	6.2	%
Acquisitions:
Proved properties(1)		37,741	22.8	%
Unproved properties		5,163	3.1	%
Exploration activities		9,295	5.6	%
Total	$	165,838	100.0	%

(1) Includes $17,628 of amounts disbursed from escrow related to title defects on the Calumet acquisition.

In addition to the capital expenditures for oil and gas properties, we spent $20.0 million for the acquisition of Green Country Supply and approximately $13.1 million for the acquisition and construction of new office and administrative facilities and equipment during the first nine months of 2007.

We also spent $2.1 million for the acquisition of land associated with a real estate development project operated under Pointe Vista Development, L.L.C., and capitalized $1.4 million of costs associated with the design and construction of an ethanol plant operated under Oklahoma Ethanol, L.L.C., both of which are unrestricted subsidiaries.

During the first nine months of 2007, we borrowed $93.0 million under our revolving credit facility. We also issued $325.0 million of our 8 ⁷/8% Senior Notes due 2017, generating net proceeds of $315.1 million after expenses.

As of September 30, 2007, we had cash and cash equivalents of $15.0 million and long-term debt obligations of $1.1 billion.

Our credit facility.As of September 30, 2007, we had $430.0 million outstanding under our Credit Agreement and the borrowing base was $500.0 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

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compliance purposes differs from current assets and current liabilities determined in compliance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2006 and September 30, 2007, our current ratio as computed using generally accepted accounting principles was 0.88 and 0.99, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 2.15 and 1.76, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

(dollars in thousands)	December 31, 2006			September 30, 2007
Current assets per GAAP	$	91,863		$	121,336
Plus—Availability under Credit Agreement		112,136			68,326
Less—Deferred tax asset on hedges and asset retirement obligation		(847	)		(5,687	)
Less—Short-term derivative instruments		(7,599	)		—
Current assets as adjusted	$	195,553		$	183,975
Current liabilities per GAAP	$	104,255		$	122,970
Less—Short-term derivative instruments		(12,376	)		(17,728	)
Less—Short-term asset retirement obligation		(749	)		(749	)
Current liabilities as adjusted	$	91,130		$	104,493
Current ratio for loan compliance		2.15			1.76

On October 31, 2006, we entered into a Seventh Restated Credit Agreement in conjunction with the Calumet acquisition. The Credit Agreement provides for a $500.0 million maximum commitment amount, is secured by our oil and gas properties and matures on October 31, 2010. Obligations under the Credit Agreement are also secured by pledges by us and each of the borrowers of equity interests in other subsidiaries owned by us and them, excluding specified entities. Availability under our Credit Agreement is subject to a borrowing base of $500.0, 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. The indentures governing our 8 ¹/2% Senior Notes and 8 ⁷/8% Senior Notes also contain restrictions as to the amount we may borrow under our credit agreement. As of September 30, 2007 the availability under our credit agreement pursuant to the restrictions contained in the indentures exceeded the allowable borrowing base. Effective November 1, 2007, our borrowing base was adjusted to $525.0 million. As part of the redetermination, we have committed to hedging 80% of our internally estimated PDP crude oil production for 2008, 2009 and 2010 and 75% and 25% of our internally estimated PDP natural gas production for 2008 and 2009, respectively.

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

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2007, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at LIBOR, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the agreement, plus a margin where the margin varies from 1.25% to 2.50% depending on the utilization percentage of the conforming borrowing base. At September 30, 2007, the LIBOR rate was 5.54%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 1.82% resulting in an effective interest rate of 7.36% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus ¹/2 of 1%; plus a margin where the margin varies from 0.00% to 1.00% depending on the utilization percentage of the borrowing base. At September 30, 2007, the applicable rate was 8.25% and the applicable margin was 0.25% resulting in an effective interest rate of 8.50% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

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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 that constitutes more than 5% of our borrowing base;

• 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 also requires us to maintain a Consolidated Total Debt to Consolidated EBITDAX Ratio, as defined in our Credit Agreement, of not greater than:

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

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

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

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

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

As of March 31, 2007, we did not meet the 5.00 to 1.0 Consolidated Total Debt to Consolidated EBITDAX ratio as required by the Credit Agreement. Effective May 11, 2007, the Credit Agreement was amended to replace the Total Debt to EBITDAX ratio with a Consolidated Senior Total Debt to Consolidated EBITDAX ratio. For 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, 2007.

The Credit Agreement also specifies events of default, including:

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

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

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• 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 million;

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

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

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

On or after February 1, 2012, we may redeem some or all of the 8 ⁷/8 % Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

In addition, upon completion of a qualified equity offering prior to February 1, 2010, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 ⁷/8% Senior Notes from the proceeds, so long as:

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

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

Finally, prior to February 1, 2012, the notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indenture.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8 ⁷/8% Senior Notes. The provisions of the indenture limit our and our restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness;

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

• make investments;

• incur liens

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

• engage in transactions with our affiliates;

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

• consolidate, merge or transfer assets.

If we experience a change of control (as defined in the indenture governing the 8 ⁷/8% Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the 8 ⁷/8% Senior Notes the opportunity to sell us their 8 ⁷/8% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

In connection with the issuance of our 8 ⁷/8% Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for other freely tradable notes and complete such exchange offer within 270 days of the issue

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date. If we fail to complete the exchange offer within 270 days after the issue date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate will increase an additional 0.25% for each additional 90 days, up to a total of 1.0%. Once the exchange offer has been completed by us, the liquidated damages will cease to accrue.

During September 2007, we determined that the exchange offer would not be completed within the 270 day window as required by the registration rights agreement. As a result, the Company accrued liquidated damages of $0.2 million during the three months ended September 30, 2007.

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

Oil and gas properties.

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

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

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

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

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

• Future development and abandonment costs. Our future development cost include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and gas properties and related facilities. We develop estimates of 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 judgements 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.

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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 gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our nine months ended September 30, 2007 production, our gross revenues from oil and gas sales would change approximately $1.5 million for each $0.10 change in gas prices and $2.5 million for each $1.00 change in oil prices.

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

We also use derivative financial instruments to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for gas from a specified delivery point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays 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 derivative losses. Also, as a result of the acquisition, Chaparral assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges.

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Our outstanding oil and natural gas derivative instruments as of September 30, 2007 are summarized below:

	Natural Gas basis protection swaps		Natural Gas Swaps				Crude Oil Swaps
	Non-hedge		Hedge		Percent of PDP production hedged(1)		Hedge		Non-hedge			Percent of PDP production(1)(2)
	Volume MMcf	Weighted average fixed price to be received	Volume MMcf	Weighted average fixed price to be received			Volume MBbl	Weighted average fixed price to be received	Volume MBbl	Weighted average fixed price to be received
4Q 2007	2,220	1.02	3,900	8.04	71.9	%	603	63.84	—		—	67.2	%
1Q 2008	2,070	1.16	960	10.07	18.7	%	543	68.02	60	$	67.48	70.4	%
2Q 2008	2,220	0.81	870	8.10	17.9	%	513	67.85	60		67.63	69.2	%
3Q 2008	2,220	0.81	610	8.14	13.2	%	508	68.05	60		67.64	70.7	%
4Q 2008	2,120	0.90	450	8.72	10.2	%	472	68.58	74		67.41	69.8	%
1Q 2009	2,070	0.92	—	—	—		402	67.84	111		67.15	67.3	%
2Q 2009	540	0.82	—	—	—		402	67.44	90		66.94	68.7	%
3Q 2009	—	—	—	—	—		402	67.02	90		66.57	70.3	%
4Q 2009	—	—	—	—	—		402	66.61	90		66.18	72.0	%
1Q 2010	—	—	—	—	—		366	66.34	102		65.80	71.4	%
2Q 2010	—	—	—	—	—		366	66.03	90		65.47	71.2	%
3Q 2010	—	—	—	—	—		366	65.57	90		65.10	72.9	%
4Q 2010	—	—	—	—	—		366	65.20	90		64.75	74.4	%
1Q 2011	—	—	—	—	—		309	64.40	99		64.24	67.8	%
2Q 2011	—	—	—	—	—		309	64.06	90		63.93	67.5	%
3Q 2011	—	—	—	—	—		309	63.71	90		63.61	68.7	%
4Q 2011	—	—	—	—	—		309	63.33	90		63.30	70.2	%
	13,460		6,790				6,947		1,376

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

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

Interest rates. All of the outstanding borrowings under our Credit Agreement as of September 30, 2007 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $500.0 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 $5.0 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 the Company’s 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 the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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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.

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. 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 judgement confirming this position. As of September 30, 2007, the recorded receivable was approximately $14.4 million, of which approximately $9.8 million is in dispute, and was recorded in accounts receivable 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

Information with respect to risk factors is included under Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2006. There have been no material changes to the risk factors since the filing of such Form 10-K.

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ITEM 6. EXHIBITS

Exhibit No.	Description
3.1*	Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
3.2*	Amended and Restated Bylaws of the Company, dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
4.1*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.2). (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.2*	Indenture, dated as of December 1, 2005, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.3*	First Supplemental Indenture, dated as of August 24, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on August 28, 2006)
4.4*	Second Supplemental Indenture, dated as of October 31, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
4.5*	Third Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 2007)
4.6*	Indenture dated January 18, 2007, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
4.7*	Form of 8 7/8% Senior Note due 2017 (included in Exhibit 4.5). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
4.8*	First Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, to Indenture dated as of January 18, 2007 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.8 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 2007)

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Exhibit No.	Description
10.1*	Second Amendment to Seventh Restated Credit Agreement, dated as of July 3, 2007, by and among the Company, Chaparral Energy, L.L.C., as Borrower Representative for the Borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.11 to the Company’s Registration on Form S-1 (SEC File No. 333-130749), filed on July 20, 2007)
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Incorporated by reference

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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, 2007

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EXHIBIT INDEX

Exhibit No.	Description
3.1*	Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”), dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
3.2*	Amended and Restated Bylaws of the Company, dated as of September 26, 2006. (Incorporated by reference to Exhibit 3.4 to the Company’s Quarterly Report on Form 10-Q, filed on November 14, 2006)
4.1*	Form of 8 1/2% Senior Note due 2015 (included in Exhibit 4.2). (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.2*	Indenture, dated as of December 1, 2005, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-1 (SEC File No. 333-130749), filed on December 29, 2005)
4.3*	First Supplemental Indenture, dated as of August 24, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on August 28, 2006)
4.4*	Second Supplemental Indenture, dated as of October 31, 2006, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on November 6, 2006)
4.5*	Third Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, to Indenture dated as of December 1, 2005 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.5 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 2007)
4.6*	Indenture dated January 18, 2007, among the Company, as Issuer, the subsidiaries of the Company party thereto as Guarantors and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
4.7*	Form of 8 7/8% Senior Note due 2017 (included in Exhibit 4.5). (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on January 24, 2007)
4.8*	First Supplemental Indenture, dated as of July 30, 2007 and effective as of April 16, 2007, to Indenture dated as of January 18, 2007 among the Company, as Issuer, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee. (Incorporated by reference to Exhibit 4.8 to the Company’s Registration Statement on Form S-4 (SEC File No. 333-145128), filed on August 3, 2007)

Exhibit No.	Description
10.1*	Second Amendment to Seventh Restated Credit Agreement, dated as of July 3, 2007, by and among the Company, Chaparral Energy, L.L.C., as Borrower Representative for the Borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (Incorporated by reference to Exhibit 10.11 to the Company’s Registration on Form S-1 (SEC File No. 333-130749), filed on July 20, 2007)
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Incorporated by reference