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 June 30, 2009

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer  ¨        Accelerated Filer  ¨        Non-Accelerated Filer  x        Smaller Reporting Company  ¨

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

877,000 shares of the registrant’s common stock were outstanding as of August 13, 2009.

CHAPARRAL ENERGY, INC.

Index to Form 10-Q

	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of December 31, 2008 and June 30, 2009 (Unaudited)	5
Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2009 (Unaudited)	6
Consolidated Statements of Cash Flows for the six months ended June 30, 2008 and 2009 (Unaudited)	7
Notes to Consolidated Financial Statements (Unaudited)	9
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Overview	22
Liquidity and Capital Resources	25
Results of Operations	30
Critical Accounting Policies and Estimates	34
Recent Accounting Pronouncements	36
Item 3. Quantitative and Qualitative Disclosures About Market Risk	36
Item 4. Controls and Procedures	39
Part II. OTHER INFORMATION	39
Item 1. Legal Proceedings	39
Item 1A. Risk Factors	39
Item 6. Exhibits	39
Signatures	41
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)

2

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 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 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 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.

3

GLOSSARY OF OIL AND GAS TERMS

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

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

• BBtu. One billion British thermal units.

• Bcf. One billion cubic feet of natural gas.

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

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

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

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

• Mcf. One thousand cubic feet of natural gas.

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

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

• MMcf. One million cubic feet of natural gas.

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

• NYMEX. The New York Mercantile Exchange.

• PDP. Proved developed producing.

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

• Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

4

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

(Dollars in thousands, except per share data)	December 31, 2008			June 30, 2009 (unaudited)
Assets
Current assets:
Cash and cash equivalents	$	52,112		$	84,276
Accounts receivable, net		63,957			44,698
Production tax benefit		13,685			43
Inventories		13,552			10,863
Prepaid expenses		4,114			4,328
Derivative instruments		51,412			37,939
Assets held for sale		19,531			4,004
Total current assets		218,363			186,151
Property and equipment—at cost, net		65,759			62,606
Oil & gas properties, using the full cost method:
Proved		1,751,096			1,844,682
Unproved (excluded from the amortization base)		16,865			16,797
Work in progress (excluded from the amortization base)		31,893			1,779
Accumulated depreciation, depletion, amortization and impairment		(573,233	)		(863,730	)
Total oil & gas properties		1,226,621			999,528
Funds held in escrow		2,350			1,662
Derivative instruments		157,720			16,131
Deferred income taxes		—			71,337
Assets held for sale		7,744			2,576
Other assets		34,279			18,569
	$	1,712,836		$	1,358,560
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	89,744		$	49,064
Accrued payroll and benefits payable		9,215			10,415
Accrued interest payable		15,408			14,394
Revenue distribution payable		19,827			17,391
Current maturities of long-term debt and capital leases		5,536			5,041
Derivative instruments		—			5,420
Deferred income taxes		19,696			12,388
Liabilities associated with discontinued operations		3,697			1,033
Total current liabilities		163,123			115,146
Long-term debt and capital leases, less current maturities		615,936			526,604
Senior notes, net		647,675			647,774
Derivative instruments		3,388			22,466
Deferred compensation		762			815
Asset retirement obligations		33,075			34,712
Deferred income taxes		42,699			—
Liabilities associated with discontinued operations		1,778			185
Commitments and contingencies (note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Common stock, $.01 par value, 3,000,000 shares authorized; 877,000 shares issued and outstanding as of December 31, 2008 and June 30, 2009, respectively		9			9
Additional paid in capital		100,918			100,918
Retained earnings (accumulated deficit)		21,340			(121,208	)
Accumulated other comprehensive income, net of taxes		82,133			31,139
		204,400			10,858
	$	1,712,836		$	1,358,560

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

5

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Three months ended June 30,						Six months ended June 30,
(Dollars in thousands, except per share data)	2008 (unaudited)			2009 (unaudited)			2008 (unaudited)			2009 (unaudited)
Revenues:
Oil and gas sales	$	157,668		$	69,064		$	278,696		$	122,931
Gain (loss) from oil and gas hedging activities		(58,230	)		6,188			(89,355	)		21,691
Total revenues		99,438			75,252			189,341			144,622
Costs and expenses:
Lease operating		26,367			23,557			53,912			50,965
Production tax		10,601			4,941			18,516			8,801
Depreciation, depletion and amortization		24,934			25,230			48,645			55,400
Loss on impairment of oil & gas properties		—			—			—			240,790
Litigation settlement		—			—			—			2,928
General and administrative		7,829			5,906			14,081			12,274
Total costs and expenses		69,731			59,634			135,154			371,158
Operating income (loss)		29,707			15,618			54,187			(226,536	)
Non-operating income (expense):
Interest expense		(21,101	)		(22,720	)		(42,621	)		(45,184	)
Non-hedge derivative gains (losses)		(58,499	)		(33,019	)		(67,181	)		17,308
Other income		669			2,783			1,154			13,750
Net non-operating expense		(78,931	)		(52,956	)		(108,648	)		(14,126	)
Loss from continuing operations before income taxes		(49,224	)		(37,338	)		(54,461	)		(240,662	)
Income tax benefit		(18,903	)		(14,175	)		(20,931	)		(92,617	)
Loss from continuing operations		(30,321	)		(23,163	)		(33,530	)		(148,045	)
Income from discontinued operations, net of related taxes		269			5,439			511			5,497
Net loss	$	(30,052	)	$	(17,724	)	$	(33,019	)	$	(142,548	)
Net income (loss) per share (basic and diluted):
Continuing operations	$	(34.57	)	$	(26.41	)	$	(38.23	)	$	(168.81	)
Discontinued operations		0.30			6.20			0.58			6.27
Net income (loss) per share (basic and diluted):	$	(34.27	)	$	(20.21	)	$	(37.65	)	$	(162.54	)
Weighted average number of shares used in calculation of basic and diluted net income (loss) per share		877,000			877,000			877,000			877,000

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

6

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Six months ended June 30,
(Dollars in thousands)	2008 (unaudited)			2009 (unaudited)
Cash flows from operating activities
Net loss	$	(33,019	)	$	(142,548	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion & amortization		48,645			55,400
Depreciation, depletion & amortization of discontinued operations		522			499
Loss on impairment of oil and gas properties		—			240,790
Litigation settlement		—			2,928
Deferred income taxes		(20,612	)		(89,178	)
(Gain) loss from hedge ineffectiveness and reclassification adjustments		28,098			(18,759	)
Change in fair value of non-hedge derivative instruments		67,181			(17,308	)
Gain on sale of ESP Division of GCS and other assets		(230	)		(9,005	)
Other		777			1,359
Change in assets and liabilities
Accounts receivable		(14,410	)		39,649
Inventories		(276	)		3,310
Prepaid expenses and other assets		3,614			9,946
Accounts payable and accrued liabilities		23,560			(6,466	)
Revenue distribution payable		8,231			(2,436	)
Deferred compensation		2,393			(149	)
Net cash provided by operating activities		114,474			68,032
Cash flows from investing activities
Purchase of property and equipment and oil and gas properties		(151,443	)		(99,605	)
Proceeds from sale of ESP Division of GCS		—			24,650
Proceeds from dispositions of property and equipment and oil and gas properties		1,610			437
Settlement of non-hedge derivative instruments		(4,559	)		132,466
Cash in escrow		2,596			389
Net cash provided by (used in) investing activities		(151,796	)		58,337
Cash flows from financing activities
Proceeds from long-term debt		47,541			—
Repayment of long-term debt		(2,272	)		(91,922	)
Principal payments under capital lease obligations		(100	)		(126	)
Settlement of derivative instruments acquired		108			—
Fees paid related to financing activities		(647	)		(2,157	)
Net cash provided by (used in) financing activities		44,630			(94,205	)
Net increase in cash and cash equivalents		7,308			32,164
Cash and cash equivalents at beginning of period		11,687			52,112
Cash and cash equivalents at end of period	$	18,995		$	84,276
Supplemental cash flow information
Cash paid during the period for:
Interest, net of capitalized interest	$	37,471		$	44,276
Income taxes		—			—

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

7

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—(Continued)

Supplemental disclosure of investing and financing activities

During the six months ended June 30, 2008 and 2009, we entered into capital lease obligations of $448 and $111, respectively, for the purchase of machinery and equipment.

During the six months ended June 30, 2008, oil and gas property additions of $3,701 were recorded as increases to accounts payable and accrued expenses, and were reflected in cash used in investing activities in the periods that the payables were settled. During the six months ended June 30, 2009, oil and gas property additions of $35,089 previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities.

We also recorded a non-cash reduction in oil and gas properties and a corresponding increase in accounts receivable of $4,845 during the six months ended June 30, 2008. This amount represents loss of well control insurance proceeds for costs incurred prior to June 30, 2008 on the Bowdle 47 No. 2 well. During the six months ended June 30, 2009, we received the final insurance settlement of $1,910, which was recorded as a reduction in cash paid for the purchase of property and equipment and oil and gas properties.

During the six months ended June 30, 2008 and 2009, we recorded an asset and related liability of $500 and $300, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and gas properties.

Interest of $681 and $410 was capitalized during the six months ended June 30, 2008 and 2009, respectively, primarily related to unproved oil and gas leaseholds.

8

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, Kansas, 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 June 30, 2009, and for the three months and six months ended June 30, 2008 and 2009, 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 six months ended June 30, 2009, are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2009.

The consolidated interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations contained in our Form 10-K filed with the Securities and Exchange Commission on March 31, 2009.

Principles of consolidation

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

Reclassifications

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

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.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of June 30, 2009, cash and funds held in escrow with a recorded balance totaling $81,494 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

9

Fair value measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. This statement is effective for fiscal years and interim periods beginning after November 15, 2007.

We elected to implement this Statement with the one-year deferral permitted by FASB Staff Position (“FSP”) 157-2, Effective Date of FASB Statement No. 157 (“FSP 157-2”), for nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed on a recurring basis (at least annually). We adopted the provisions of SFAS 157 for our financial assets and financial liabilities measured at fair value on January 1, 2008. We adopted the provisions of SFAS 157 for our nonfinancial assets and nonfinancial liabilities measured at fair value on a non-recurring basis on January 1, 2009. The implementation of SFAS 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating the impact of nonperformance risk on derivative instruments. The primary impact from adoption was additional disclosures.

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

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

In April 2009, the FASB issued three FSPs to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. FSP FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, provides guidelines for making fair value measurements more consistent with the principles presented in SFAS No. 157. FSP FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments, enhances consistency in financial reporting by increasing the frequency of fair value disclosures. FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments, provides additional guidance in accounting for and presenting impairment losses on securities. These three FSPs are effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the provisions of these FSPs for the period ending March 31, 2009. The adoption of these FSPs resulted in additional disclosures, but did not have an impact on our financial position or results of operations.

Net income (loss) per share

Basic net income (loss) per share is computed by dividing net income (loss) 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 net income (loss) per share is determined in the same manner as basic net income (loss) 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.

10

Accounts receivable

Accounts receivable consisted of the following at December 31, 2008 and June 30, 2009:

	December 31, 2008			June 30, 2009
Joint interests	$	21,136		$	13,907
Accrued oil and gas sales		27,432			27,195
Hedge settlements		15,315			4,146
Other		654			125
Allowance for doubtful accounts		(580	)		(675	)
	$	63,957		$	44,698

Inventories

Inventories are comprised of equipment used in developing oil and gas properties, oil and gas production inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and records provisions for excess or obsolete inventory, if necessary. Inventories at December 31, 2008 and June 30, 2009 consisted of the following:

	December 31, 2008			June 30, 2009
Equipment inventory	$	10,484		$	8,391
Oil and gas product		3,467			3,272
Inventory valuation allowance		(399	)		(800	)
	$	13,552		$	10,863

Oil and gas properties

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

In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009, spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240,790 during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009, spot prices, increased the full cost ceiling by $169,013, thereby reducing the ceiling test write down by the same amount.

The internally estimated PV-10 value of our reserves was estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per Mcf of gas at June 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these June 30, 2009, spot prices, reduced the full cost ceiling by $12,928. The qualifying cash flow hedges as of June 30, 2009, which consisted of commodity price swaps, covered 4,265 MBbls of oil production for the period from July 2009 through December 2011. As of June 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the second quarter of 2009.

A decline in oil and gas prices subsequent to June 30, 2009, could result in additional ceiling test write downs in the third quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of or during each period, the incremental proved reserves added during each period, and additional capital spent.

11

Production tax benefit asset

During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15,000. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of December 31, 2008 and June 30, 2009, the carrying value of the production tax benefit asset was $13,685 and $43, respectively. Oklahoma production tax credits of $323 and $2,684, respectively, for the three months ended June 30, 2008 and 2009 and $688 and $13,544, respectively, for the six months ended June 30, 2008 and 2009 were included in other income in the consolidated statements of operations.

Funds held in escrow

We have funds held in escrow that are restricted as to withdrawal or usage. The restricted amounts consisted of the following:

	December 31, 2008		June 30,     2009
Escrow from acquisitions	$	692	$	—
Plugging and abandonment escrow		1,658		1,662
	$	2,350	$	1,662

We are 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 Unit, provided that written documentation has been provided. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.

Impairment of long-lived assets

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

Asset retirement obligations

We account for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, and well life, all of which are Level 3 inputs according to the SFAS 157 fair value hierarchy. These estimates may change based upon future inflation rates and changes in statutory remediation rules.

Deferred income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We 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 assets will not be realized.

We account for uncertain tax positions in accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement No. 109 (“FIN 48”). If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2008 and June 30, 2009, we have not recorded a liability or accrued interest related to uncertain tax positions.

The tax years 1998 through 2009 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

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Recently issued accounting standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS 141(R)”), which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree and the goodwill acquired. SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008. We adopted the provisions of SFAS 141(R) effective January 1, 2009. This statement will apply prospectively to future business combinations, and did not have an effect on our reported financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 addresses concerns that the existing disclosure requirements in SFAS 133 do not provide adequate information about how derivative and hedging activities affect an entity’s financial position, financial performance, and cash flows. Accordingly, this statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements of SFAS 161 beginning January 1, 2009. The adoption of this statement did not have an impact on our financial position or results of operations.

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

In May 2009, the FASB issued SFAS No. 165, Subsequent Events (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist. This statement, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. We adopted the statement for the period ending June 30, 2009. The adoption of this statement did not have an impact on our financial position or results of operations.

Subsequent events

As of August 13, 2009, which is the date these financial statements were issued, there are no additional material subsequent events requiring additional disclosure in or amendment to these financial statements.

Note 2: Discontinued operations

During the second quarter of 2009, we committed to a plan to sell the assets of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the Electric Submersible Pumps Division of GCS (the “ESP Division”) to Global Oilfield Services, Inc. (“Global”) for a cash price of $26,000, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24,650 in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1,350 due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1,605. The purchase price is subject to a final working capital adjustment on or before August 27, 2009. As of June 30, 2009, we recorded a pre-tax gain associated with the sale of $9,004. All taxable income associated with such gain was offset by existing net operating losses.

The operating results of GCS for the three and six months ended June 30, 2008 and 2009 have been reclassified as discontinued operations in the consolidated statements of operations as detailed in the table below.

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Revenues	$	8,331		$	3,314		$	16,070		$	8,113
Operating expenses		(7,896	)		(3,476	)		(15,240	)		(8,181	)
Gain on sale		—			9,004			—			9,004
Income before income taxes		435			8,842			830			8,936
Income tax provision		(166	)		(3,403	)		(319	)		(3,439	)
Income from discontinued operations	$	269		$	5,439		$	511		$	5,497

At December 31, 2008 and June 30, 2009, the assets and liabilities of GCS are classified as assets held for sale and liabilities associated with discontinued operations, respectively, on our consolidated balance sheets.

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Note 3: Derivative activities and financial instruments

Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

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

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not believe that these instruments qualify as hedges pursuant to SFAS 133; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

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

As part of the Calumet acquisition, we assumed the existing Calumet swaps on October 31, 2006 and designated these as cash flow hedges. In accordance with SFAS No. 141, Business Combinations, these derivative positions were recorded at fair value in the purchase price allocation as a liability of $838. Because of this accounting treatment, only cash settlements for changes in fair value subsequent to the acquisition date for the derivative positions assumed result in adjustments to our oil and 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 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 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. In addition, the hedge instruments are deemed to contain a significant financing element, and all cash flows associated with these positions are reported as a financing activity in the consolidated statement of cash flows for the periods in which settlement occurs. All of these positions were settled as of December 31, 2008.

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Our outstanding oil and gas derivative instruments as of June 30, 2009, are summarized below:

	Oil derivatives
	Swaps			Collars
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range to be received
2009	1,304	$	67.32	120	$	110.00 - $164.28
2010	2,277		67.07	240		110.00 -   168.55
2011	1,605		63.86	204		110.00 -   152.71
	5,186			564

	Gas derivatives						Natural gas basis protection swaps
	Swaps			Collars
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range to be received		Volume BBtu	Weighted average fixed price to be paid
2009	4,490	$	8.09	1,980	$	10.00 - $13.85	9,060	$	0.92
2010	12,600		7.43	3,360		10.00 -   11.53	15,050		0.84
2011	9,600		7.42	—			11,250		0.77
	26,690			5,340			35,360

All derivative financial instruments are recorded on the balance sheet at fair value. The fair value of swaps is generally determined based on the difference between the fixed contract price and the underlying published forward market price. The fair value of collars is determined using an option pricing model which takes into account market volatility, market prices, and contract parameters. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable. None of our derivative contracts have margin requirements, collateral provisions, or other credit-risk-related contingent features that would require funding prior to the scheduled cash settlement date.

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

	As of December 31, 2008							As of June 30, 2009
	Assets		Liabilities			Net Value		Assets		Liabilities			Net Value
Derivatives designated as cash flow hedges:
Oil swaps	$	116,311	$	(5,631	)	$	110,680	$	1,104	$	(36,759	)	$	(35,655	)
Derivatives not designated as hedging instruments:
Gas swaps		14,043		(731	)		13,312		36,786		—			36,786
Oil swaps		2,424		(1,688	)		736		—		(9,558	)		(9,558	)
Gas collars		21,682		—			21,682		23,990		—			23,990
Oil collars		57,716		—			57,716		19,239		—			19,239
Natural gas basis differential swaps		2,093		(475	)		1,618		—		(8,618	)		(8,618	)
Total non-hedge instruments		97,958		(2,894	)		95,064		80,015		(18,176	)		61,839
Total derivative instruments		214,269		(8,525	)		205,744		81,119		(54,935	)		26,184
Less:
Netting adjustments (1)		5,137		(5,137	)		—		27,049		(27,049	)		—
Current portion asset (liability)		51,412		—			51,412		37,939		(5,420	)		32,519
	$	157,720	$	(3,388	)	$	154,332	$	16,131	$	(22,466	)	$	(6,335	)

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

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Changes in the fair value of effective cash flow hedges are recorded as a component of accumulated other comprehensive income (“AOCI”), 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, and is included in gain (loss) from oil and gas hedging activities in the consolidated statements of operations. If it is probable the oil or gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in AOCI is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur.

Gains and losses associated with cash flow hedges are summarized below.

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Amount of gain (loss) recognized in AOCI (effective portion)
Oil swaps	$	(256,728	)	$	(57,944	)	$	(303,752	)	$	(59,444	)
Gas swaps		(24,866	)		—			(44,729	)		—
Income taxes		108,926			22,402			134,802			22,993
	$	(172,668	)	$	(35,542	)	$	(213,679	)	$	(36,451	)
Amount of gain (loss) reclassified from AOCI in income (effective portion)(1)
Oil swaps	$	(25,647	)	$	6,761		$	(41,297	)	$	19,072
Gas swaps		(7,065	)		1,758			(6,215	)		4,645
Income taxes		12,653			(3,190	)		18,379			(9,174	)
	$	(20,059	)	$	5,329		$	(29,133	)	$	14,543
Amount of loss recognized in income (ineffective portion)(1)
Oil swaps	$	(11,747	)	$	(2,331	)	$	(14,399	)	$	(2,026	)
Gas swaps		(13,771	)		—			(27,444	)		—
	$	(25,518	)	$	(2,331	)	$	(41,843	)	$	(2,026	)

(1) Included in gain (loss) from oil and gas hedging activities in the consolidated statements of operations.

During the fourth quarter of 2008, we determined that our gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income and the ineffective portion would have been included in gain (loss) from oil and gas hedging activities.

In addition, during the fourth quarter of 2008, we early settled oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32,589. During the first quarter of 2009, we early settled additional gas swaps with original settlement dates from May through October of 2009 for proceeds of $9,522. During the second quarter of 2009, we early settled additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102,352. Certain swaps that were early settled had previously been accounted for as cash flow hedges. As of December 31, 2008, and June 30, 2009, accumulated other comprehensive income included $23,662 and $86,436, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. No oil and gas derivatives were early settled during the first six months of 2008.

Gains of $7,887 and $19,159 associated with derivatives for which hedge accounting had previously been discontinued, were reclassified into earnings during the three and six months ended June 30, 2009, respectively, as the hedged production was sold. There were no gains or losses associated with the discontinuance of hedge accounting treatment during the three and six months ended June 30, 2008. Gain (loss) from oil and gas hedging activities, which is a component of total revenues in the consolidated statements of operations, is comprised of the following:

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Oil derivatives
Reclassification adjustment for hedge gains (losses) included in net loss	$	(25,647	)	$	6,761		$	(41,297	)	$	19,072
Loss on ineffective portion of derivatives qualifying for hedge accounting		(11,747	)		(2,331	)		(14,399	)		(2,026	)
Gas derivatives
Reclassification adjustment for hedge gains (losses) included in net loss		(7,065	)		1,758			(6,215	)		4,645
Loss on ineffective portion of derivatives qualifying for hedge accounting		(13,771	)		—			(27,444	)		—
Total	$	(58,230	)	$	6,188		$	(89,355	)	$	21,691

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Based upon market prices at June 30, 2009, and assuming no future change in the market, we expect to reclassify $4,641 of the balance in accumulated other comprehensive income to income during the next 12 months when the forecasted transactions actually occur. All forecasted transactions hedged as of June 30, 2009, are expected to be settled by December 2011.

The changes in fair value and settlement of derivative contracts that do not qualify or have not been designated as hedges in accordance with SFAS 133 are recognized as non-hedge derivative gains (losses). All non-hedge derivative contracts outstanding at June 30, 2009, are expected to be settled by December 2011. Non-hedge derivative gains (losses) in the consolidated statements of operations are comprised of the following:

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Change in fair value of non-qualified commodity price swaps	$	(51,058	)	$	(98,665	)	$	(58,880	)	$	(68,753	)
Change in fair value of non-designated costless collars		(8,557	)		(39,331	)		(8,557	)		(36,169	)
Change in fair value of natural gas basis differential contracts		3,119			(5,910	)		4,815			(10,236	)
Receipts from (payments on) settlement of non-qualified commodity price swaps		(3,380	)		84,499			(5,206	)		99,229
Receipts from settlement of non-designated costless collars		—			27,267			—			32,345
Receipts from (payments on) settlement of natural gas basis differential contracts		1,377			(879	)		647			892
	$	(58,499	)	$	(33,019	)	$	(67,181	)	$	17,308

Derivative settlements receivable of $15,315 and $4,146 were included in accounts receivable at December 31, 2008 and June 30, 2009, respectively. Derivative settlements payable of $0 and $3,617 were included in accounts payable and accrued liabilities at December 31, 2008 and June 30, 2009, respectively.

We have no Level 1 assets or liabilities as of June 30, 2009. Our derivative contracts classified as Level 2 are valued using quotations provided by price index developers such as Platts and Oil Price Information Service. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

The fair value hierarchy for our financial assets and liabilities as of December 31, 2008 and June 30, 2009, accounted for at fair value on a recurring basis is shown by the following tables.

	As of December 31, 2008								As of June 30, 2009
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	134,666		$	(8,525	)	$	126,141	$	37,890		$	(54,935	)	$	(17,045	)
Significant unobservable inputs (Level 3)		79,603			—			79,603		43,229			—			43,229
Netting adjustments (1)		(5,137	)		5,137			—		(27,049	)		27,049			—
	$	209,132		$	(3,388	)	$	205,744	$	54,070		$	(27,886	)	$	26,184

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

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Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at June 30, 2009, were:

Six months ended June 30, 2009	Net derivative assets
Beginning balance	$	79,603
Total realized and unrealized gains included in non-hedge derivative gains (losses)		(3,739	)
Purchases, issuances, and settlements		(32,635	)
Ending balance	$	43,229
The amount of total gains for the period included in non-hedge derivative gains (losses) attributable to the change in unrealized gains relating to assets still held at the reporting date	$	1,632

Fair value of financial instruments

The carrying values of items comprising current assets and current liabilities, other than derivatives, approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2008, and June 30, 2009, approximates fair value because substantially all debt carries variable market rates. Based on market prices, at December 31, 2008, the fair value of the 8 ¹/2 % Senior Notes and 8 ⁷/8 % Senior Notes were $73,125 and $73,125, respectively. Based on market prices, at June 30, 2009, the fair value of the 8 ¹/2 % Senior Notes and 8 ⁷/8 % Senior Notes were $201,500 and $201,500, respectively.

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

Note 4: Asset retirement obligations

The following table provides a summary of our asset retirement obligations for June 30, 2009.

	Six months ended June 30, 2009
Beginning balance	$	33,375
Liabilities incurred in current period		300
Liabilities settled in current period		(89	)
Accretion expense		1,426
	$	35,012
Less current portion		300
	$	34,712

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Note 5: Long-term debt

Long-term debt at December 31, 2008, and June 30, 2009, consisted of the following:

	December 31, 2008		June 30, 2009
Revolving credit line with banks	$	594,000	$	507,001
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 5.50% to 7.283%, due February 2011 through January 2029; collateralized by real property		13,806		13,676
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 4.594% to 9.658%, due July 2009 through November 2013; collateralized by automobiles, machinery and equipment		13,140		10,457
		620,946		531,134
Less current maturities		5,301		4,770
	$	615,645	$	526,364

In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010, and is collateralized by our oil and gas properties. Availability under our credit agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. As a result of our early settlement of derivatives in the second quarter of 2009, the borrowing base was reduced from $600,000 to $513,001 effective June 8, 2009.

Interest was paid at least every three months during 2008 and 2009. The effective rate of interest on the entire outstanding balance was 5.299% and 5.937% as of December 31, 2008 and June 30, 2009, respectively, and was based upon LIBOR.

The Credit Agreement has certain negative and affirmative covenants that require, among other things, maintaining financial covenants for current and debt service ratios and financial reporting. The Credit Agreement, as amended effective May 21, 2009, requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

• 2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2009;

• 3.00 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2009, September 30, 2009, December 31, 2009, and March 31, 2010; and

• 2.75 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2010, September 30, 2010, and December 31, 2010.

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, minus cash on hand in excess of accounts payable and accrued liabilities that are more than 90 days past the invoice date, as defined in the Fifth Amendment to our Credit Agreement.

The Credit Agreement, as amended, also requires us to limit the aggregate amount of our capital expenditures incurred during the period beginning April 1, 2009 and ending December 31, 2009 to our discretionary cash flows for the period. Discretionary cash flows consist of Consolidated EBITDAX minus interest expense and taxes paid during the period, as defined in the Fifth Amendment to our Credit Agreement.

We believe we were in compliance with all covenants under the Credit Agreement as of June 30, 2009.

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

Our Credit Agreement is scheduled to mature on October 31, 2010. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability. Borrowings under our Credit Agreement are excluded from the Credit Agreement definition of current liabilities. We do not expect current classification of the borrowings to impact our current ratio as calculated for loan compliance.

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

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Note 6: Related party transactions

In September 2006, Chesapeake Energy Corporation, now CHK Holdings, L.L.C., (“Chesapeake”) acquired a 31.9% beneficial interest in the Company through the sale of common stock. We participate in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings on these properties of: $2,296 and $512, respectively, for the three months ended June 30, 2008; $972 and $750, respectively, for the three months ended June 30, 2009; $4,468 and $1,330, respectively, for the six months ended June 30, 2008; and $2,636 and $2,136 respectively, for the six months ended June 30, 2009. In addition, Chesapeake participates in ownership of properties operated by us. We paid revenues and recorded joint interest billings to Chesapeake of: $489 and $397, respectively, during the three months ended June 30, 2008; $236 and $642, respectively, during the three months ended June 30, 2009; $1,113 and $1,475, respectively, during the six months ended June 30, 2008, and $620 and $1,830, respectively, during the six months ended June 30, 2009. Amounts receivable from and payable to Chesapeake were $1,914 and $1,188, respectively, as of December 31, 2008. Amounts receivable from and payable to Chesapeake were $2,014 and $1,486, respectively, as of June 30, 2009.

Note 7: Deferred compensation

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on January 1, 2007, as the First Amended and Restated Phantom Stock Plan (the “Plan”) to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to participants in total up to 2% of the fair market value of the Company. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the current plan, awards vest on the fifth anniversary of the award date, but may also vest on a pro-rata basis following a participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Upon vesting, participants are entitled to redeem their phantom stock for cash within 120 days of the vesting date.

Since the phantom stock is a liability award, fair value of the stock is remeasured at the end of each reporting period until settlement in accordance with the provisions of SFAS No. 123(R), Share Based Payments (“SFAS 123(R)”). As prescribed by the Plan, fair market value is calculated based on the Company’s total asset value less total liabilities, with both assets and liabilities being adjusted to fair value. The primary adjustment required is the adjustment of oil and gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips.

Compensation expense is recognized over the vesting period of the phantom stock and is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. Such expense is calculated net of forfeitures estimated based on our historical and expected turnover rates. We recognized deferred compensation expense as follows:

	Three months ending						Six months ending
	June 30, 2008			June 30, 2009			June 30, 2008			June 30, 2009
Deferred compensation cost	$	3,135		$	706		$	3,566		$	940
Less: deferred compensation cost capitalized		(1,029	)		(232	)		(1,173	)		(309	)
Deferred compensation expense	$	2,106			474		$	2,393			631

A summary of our phantom unit activity as of December 31, 2008, and changes during the first six months of fiscal year 2009 is presented in the following table:

	Fair value		Phantom stock units		Weighted average remaining contract term	Aggregate intrinsic value
	(Per unit)
Unvested and total outstanding at December 31, 2008	$	10.22	219,658
Granted	$	10.08	31,965
Vested	$	10.08	(77,224	)
Forfeited	$	10.22	(1,640	)
Unvested and total outstanding at June 30, 2009	$	19.05	172,759		2.29	$	3,291

As of June 30, 2009, there was approximately $1,579 of total unrecognized compensation cost related to unvested phantom units that is expected to be recognized over a weighted-average period of 2.29 years. As of December 31, 2008 and June 30, 2009, accrued payroll and benefits payable included $789 and $897, respectively, for deferred compensation costs vesting within the next twelve months.

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Note 8: Commitments and contingencies

Standby letters of credit (“Letters”) available under the revolving credit line are used in lieu of surety bonds with various city, state and federal agencies for liabilities relating to the operation of oil and gas properties. We had various Letters outstanding totaling $2,730 and $2,880 as of December 31, 2008, and June 30, 2009, respectively. Interest on each Letter accrues at the lender’s prime rate (effective rate of 5.299% at December 31, 2008, and 5.937% at June 30, 2009) for all amounts paid by the lenders under the Letters. We paid no interest on the Letters during the three and six months ended June 30, 2008 and 2009.

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

Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was filed in the District Court of Tulsa County, State of Oklahoma, and related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”). Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7,100, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $387 contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14,406, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4,378, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of June 30, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2,928.

In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10,648. Our insurance policy has covered 100% of these costs, with the $627 insurance retention and deductible being payable by us. As of June 30, 2009, we have received insurance proceeds of $10,021, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows.

Note 9: Comprehensive loss

Components of comprehensive loss, net of related tax, are as follows for the three and six months ended June 30, 2008, and 2009:

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Net loss	$	(30,052	)	$	(17,724	)	$	(33,019	)	$	(142,548	)
Unrealized loss on hedges		(172,668	)		(35,542	)		(213,679	)		(36,451	)
Reclassification adjustment for hedge (gains) losses included in net loss		20,059			(5,329	)		29,133			(14,543	)
Comprehensive loss	$	(182,661	)	$	(58,595	)	$	(217,565	)	$	(193,542	)

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

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report.

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

Overview

We are an independent oil and gas company engaged in the production, acquisition, and exploitation of oil and gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and 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 (“GAAP”) 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 gas reserves. We use the full cost method of accounting for our oil and gas activities.

Generally our producing properties have declining production rates. Our reserve estimates as of December 31, 2008, reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 17.0%, 11.4%, and 10.8% for the next three years. To grow our production and cash flow we must find, develop, and acquire new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop, and acquire oil and gas reserves.

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

• cash flow available for capital expenditures;

• ability to borrow and raise additional capital;

• ability to service debt;

• quantity of oil and gas we can produce;

• quantity of oil and gas reserves; and

• operating results for oil and gas activities.

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

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

• the quantity of our proved oil and gas reserves;

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

• the value of our derivative positions;

• the realization of deferred tax assets; and

• the full cost ceiling limitation.

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

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During the second quarter of 2009, quarterly production was 11,696 MMcfe, a 9.3% increase over production levels in the second quarter of 2008, primarily due to our capital expenditures in the Permian and Mid Continent areas during 2008. However, a 59.9% decline in our average sales price before hedging resulted in a 56.2% decrease in revenue from oil and gas sales in the second quarter of 2009 compared to the same period in 2008. Despite this decrease in revenue, the $25.5 million decline in our non-hedge derivative losses, combined with the $9.0 million gain on the sale of the Electric Submersible Pumps division (the “ESP Division”) of Green Country Supply, Inc. (“GCS”), resulted in a reduction of our net loss from $30.1 million during the second quarter of 2008 to $17.7 million during the second quarter of 2009.

All of our operating expenses, with the exception of depreciation, depletion and amortization, decreased on both an absolute and per Mcfe basis during the second quarter of 2009 compared to the same period in 2008 due to a reduction in activity and lower overall industry costs. Oil prices have recently started to improve, and if this upward trend continues, we expect operating costs to increase as well.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and debt. Due to the recent turmoil in the market and the sharp decline in oil and gas prices, which began during the fourth quarter of 2008, we plan to keep our capital expenditures within our discretionary cash flow for the period from April 1, 2009 to December 31, 2009, as required by our amended Credit Agreement.

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

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

Our cash accounts and deposits with any financial institution that exceed the amount insured by the Federal Deposit Insurance Corporation are at risk in the event one of these financial institutions should fail. As of June 30, 2009, cash with a recorded balance totaling $81.5 million was held at JP Morgan Chase Bank, N.A.

We sell our crude oil, natural gas and natural gas liquids to a variety of purchasers. Some of these parties may experience liquidity problems. Nonperformance by a trade creditor could result in losses. We also have significant net derivative assets that are held by affiliates of our lenders. As of June 30, 2009, net derivative assets totaling $48.5 million were held by JP Morgan Chase Bank, N.A., Calyon Credit Agricole CIB, The Royal Bank of Scotland plc, and Bank of Oklahoma.

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

Oil and gas prices declined significantly during the second quarter of 2009 compared to the second quarter of 2008, which will reduce our cash flows from operations in future periods in which prices remain at or below the current levels. The commodity price swaps and costless collars that cover approximately 77% of our expected PDP oil production through December 2011 and approximately 70% of our expected PDP gas production through December 2011 will, however, become more valuable if prices continue to decline.

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• Credit Agreement. Our current Credit Agreement is a revolving credit facility in the amount of $513.0 million. At June 30, 2009, we had $507.0 million outstanding under the Credit Agreement and $2.9 million was utilized by outstanding letters of credit.

The Credit Agreement is scheduled to mature on October 31, 2010. Should current credit market volatility be prolonged, future extensions of our Credit Agreement may contain terms that are less favorable than those of our current Credit Agreement. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability. Borrowings under our Credit Agreement are excluded from the Credit Agreement definition of current liabilities. We do not expect current classification of the borrowings to impact our current ratio as calculated for loan compliance.

Covenants set forth in the indentures for our 8 ¹/2% Senior Notes and the 8 ⁷/8% Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for oil and gas at specified dates. Based on the commodity prices for oil and gas at December 31, 2008, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our Credit Agreement, unless our secured debt is reduced below approximately $330.0 million.

• Impairment of oil and gas properties. In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to the PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

The internally estimated PV-10 value of our reserves was estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per Mcf of gas at June 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these June 30, 2009, spot prices, reduced the full cost ceiling by $12.9 million. The qualifying cash flow hedges as of June 30, 2009, which consisted of commodity price swaps, covered 4,265 MBbls of oil production for the period from July 2009 through December 2011. As of June 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the second quarter of 2009.

A decline in oil and gas prices subsequent to June 30, 2009 could result in additional ceiling test write downs in the third quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of or during each period, the incremental proved reserves added during each period, and additional capital spent.

• 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 return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. As of June 30, 2009, we had received $30.0 million of proceeds from the Oklahoma tax credits.

During the three and six months ended June 30, 2009, we received cash of $5.3 million and $27.2 million, respectively, from application of these tax credits. This source of cash received will not be available in future periods.

• Discontinued Operations – During the second quarter of 2009, we committed to a plan to sell the assets of GCS, a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the ESP Division of GCS to Global Oilfield Services, Inc. (“Global”) for a cash price of $26.0 million, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24.7 million in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1.3 million due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million. The purchase price is subject to a final working capital adjustment on or before August 27, 2009. As of June 30, 2009, we recorded a pre-tax gain associated with the sale of $9.0 million. All taxable income associated with such gain was offset by existing net operating losses.

• Monetization of derivative assets. During the first quarter of 2009, we monetized certain derivative instruments with original settlement dates from May through October of 2009. Net proceeds received from this monetization were $9.5 million. None of the monetized derivatives were incorporated into the determination of the borrowing base under our Credit Agreement. During the second quarter of 2009, we monetized additional derivative instruments with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of this monetization, effective June 8, 2009, the borrowing base was reduced from $600.0 million to $513.0 million, resulting in a payment to the banks of $87.0 million. The remaining proceeds of $15.4 million increased our cash balance. As of June 30, 2009, we have a net derivative asset of $26.2 million.

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• Capital expenditure budget. We have expanded our oil and gas property capital expenditure budget for 2009 reflecting an increased amount of cash available primarily from higher oil prices, the receipt of proceeds from derivative monetizations, the sale of the ESP Division of GCS, and production tax credits. Our capital expenditures for oil and gas properties were $40.3 million and $23.9 million, respectively, during the first and second quarters of 2009. The majority of the costs incurred during the first six months of 2009 were incurred during the first quarter of 2009 as we completed projects begun during the fourth quarter of 2008. Our projected capital expenditures for the rest of 2009 are between $55 million and $65 million, which, combined with our actual capital expenditures for the second quarter of 2009, are within our projected discretionary cash flows for the period beginning April 1, 2009 and ending December 31, 2009, as required by our Credit Agreement. Discretionary cash flows consist of Consolidated EBITDAX minus interest expense and taxes paid during the period, as defined in the Fifth Amendment to our Credit Agreement. For the period from April 1, 2009 to June 30, 2009, our capital expenditures exceeded our discretionary cash flow by $2.8 million. We expect to be in compliance with the covenant as of December 31, 2009.

The expanded 2009 capital budget represents a reduction in capital expenditures of approximately 60% from our 2008 levels. Despite this reduction, we expect production for 2009 to be slightly higher than 2008 production as a result of capital investments made in 2008 and the first quarter of 2009. We plan to drill several high impact wells in the second half of 2009, which, if successful, could maintain our production levels throughout 2010. However, we cannot accurately predict the timing or level of future production.

• Insurance proceeds. In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10.6 million. Our insurance policy has covered 100% of these costs, with the $0.6 million insurance retention and deductible being payable by us. As of June 30, 2009, we have received insurance proceeds of $10.0 million, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and gas properties on the balance sheet and in the statement of cash flows.

Liquidity and capital resources

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

Historically, our primary sources of liquidity have been cash generated from our operations and debt. At June 30, 2009, we had approximately $84.3 million of cash and cash equivalents and $3.1 million of availability under our revolving credit line with a borrowing base of $513.0 million.

Covenants set forth in the indentures for our 8 ¹/2% Senior Notes and the 8 ⁷/8% Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for oil and gas at specified dates. Based on the commodity prices for oil and gas at December 31, 2008, we will be unable to borrow additional amounts under our Credit Agreement during 2009, regardless of the availability under our revolver, unless our secured debt is reduced below approximately $330.0 million.

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

We generally have had a working capital deficit as our capital expenditures have historically exceeded our cash flow, and we rely on our borrowing base for additional capital. Because of the ACNTA test limitation under our indentures, and its impact on our ability to utilize our revolving credit in 2009, we drew down substantially all our remaining availability under our Credit Agreement prior to December 31, 2008. During the fourth quarter of 2008, we also monetized certain derivative instruments with original settlement dates from January through June of 2009, which generated net proceeds of $32.6 million. During the first quarter of 2009, we monetized certain derivative instruments with original settlement dates from May through October of 2009, which generated net proceeds of $9.5 million. During the second quarter of 2009, we monetized additional derivative instruments with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. As a result of this monetization, effective June 8, 2009, the borrowing base was reduced from $600.0 million to $513.0 million, resulting in a payment to the banks of $87.0 million. The remaining proceeds of $15.4 million increased our cash balance. We have changed our cash management activities to target a minimum balance of cash on hand, which we maintain in highly liquid investments.

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

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

	Six months ended June 30,
(dollars in thousands)	2008			2009
Cash flows provided by operating activities	$	114,474		$	68,032
Cash flows provided by (used in) investing activities		(151,796	)		58,337
Cash flows provided by (used in) financing activities		44,630			(94,205	)
Net increase in cash during the period	$	7,308		$	32,164

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 six months ended June 30, 2009, net cash provided from operations decreased 40.6% from the same period in the prior year primarily due to the decrease in revenue from oil and gas sales.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Cash flows provided by investing activities for the six months ended June 30, 2009 included proceeds of $111.9 million from the monetization of derivatives and proceeds of $24.7 million from the sale of the ESP Division of GCS. A portion of the proceeds was used to pay down borrowings under our Credit Agreement.

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

(dollars in thousands)	Six months ended June 30, 2009		Percent of total
Development activities:
Developmental drilling	$	32,231	50.2	%
Enhancements		16,945	26.4	%
Tertiary recovery		7,367	11.5	%
Acquisitions:
Proved properties		494	0.7	%
Unproved properties		2,387	3.7	%
Exploration activities		4,826	7.5	%
Total	$	64,250	100.0	%

In addition to the capital expenditures for oil and gas properties, we spent approximately $1.5 million for the acquisition and construction of new office and administrative facilities and equipment during the first six months of 2009.

As of June 30, 2009, we had cash and cash equivalents of $84.3 million and long-term debt obligations of $1.2 billion.

Our Credit Agreement. In October 2006, we entered into a Seventh Restated Credit Agreement, which is scheduled to mature on October 31, 2010, and is collateralized by our oil and gas properties. Availability under our Credit Agreement is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once every six months. As a result of our derivative monetization during the second quarter of 2009, the borrowing base was reduced from $600.0 million to $513.0 million effective June 8, 2009. We had $507.0 million outstanding under our Credit Agreement at June 30, 2009.

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. We believe we were in compliance with all covenants under the Credit Agreement as of June 30, 2009.

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans. At June 30, 2009, all of our borrowings were Eurodollar loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the greater of 2% or the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in the Credit Agreement, plus a margin where the margin varies from 2.500% to 4.250% depending on the utilization percentage of the conforming borrowing base. At June 30, 2009, the Adjusted LIBO rate, as defined, was 2.000%, the Statutory Reserve Rate multiplier was 100%, and the applicable margin and commitment fee together were 3.937% resulting in an effective interest rate of 5.937% for Eurodollar borrowings. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

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Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our Credit Agreement, plus 1%; plus a margin where the margin varies from 1.625% to 3.375%, depending on the utilization percentage of the borrowing base.

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

Interest was paid at least every three months during 2008 and 2009. The effective rate of interest on the entire outstanding balance was 5.299% and 5.937% as of December 31, 2008, and June 30, 2009, respectively, and was based upon LIBOR.

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

• incur additional indebtedness;

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

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

• make investments in or loans to others;

• change our line of business;

• enter into operating leases;

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

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

• enter into transactions with affiliates;

• issue preferred stock;

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

• enter into certain swap agreements; and

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

Our Credit Agreement requires us to maintain a current ratio, as defined in our Credit Agreement, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be a useful measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2008 and June 30, 2009, our current ratio as computed using GAAP was 1.34 and 1.62, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.19 and 1.56, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:

(dollars in thousands)	December 31, 2008			June 30, 2009
Current assets per GAAP	$	218,363		$	186,151
Plus—Availability under credit agreement		3,270			3,120
Less—Short-term derivative instruments		(51,412	)		(37,939	)
Current assets as adjusted	$	170,221		$	151,332
Current liabilities per GAAP	$	163,123		$	115,146
Less—Deferred tax liability on derivative instruments and asset retirement obligations		(19,755	)		(12,447	)
Less—Short-term asset retirement obligations		(300	)		(300	)
Less—Short-term derivative instruments		—			(5,420	)
Current liabilities as adjusted	$	143,068		$	96,979
Current ratio for loan compliance		1.19			1.56

27

The monetization of derivatives in December 2008 and the first and second quarters of 2009 allowed us to exceed our required current ratio by a higher margin.

Our Credit Agreement is scheduled to mature on October 31, 2010. If we are not able to extend the maturity of our Credit Agreement before October 31, 2009, the entire balance then outstanding would be classified as a current liability for GAAP accounting purposes. Borrowings under our Credit Agreement are excluded from the Credit Agreement definition of current liabilities. We do not expect current classification of the borrowings to impact our current ratio as calculated for loan compliance.

The Credit Agreement, as amended effective May 21, 2009, requires us to maintain a Consolidated Senior Total Debt to Consolidated EBITDAX ratio, as defined in our Credit Agreement, of not greater than:

• 2.50 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2009;

• 3.00 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2009, September 30, 2009, December 31, 2009, and March 31, 2010; and

• 2.75 to 1.0 for the four consecutive fiscal quarters ending on June 30, 2010, September 30, 2010, and December 31, 2010.

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, minus cash on hand in excess of accounts payable and accrued liabilities that are more than 90 days past the invoice date, as defined in the Fifth Amendment to our Credit Agreement.

The Credit Agreement, as amended, also requires us to limit the aggregate amount of our capital expenditures incurred during the period beginning April 1, 2009 and ending December 31, 2009 to our discretionary cash flows for the period. Discretionary cash flows consist of Consolidated EBITDAX minus interest expense and taxes paid during the period, as defined in the Fifth Amendment to our Credit Agreement.

The Credit Agreement also specifies events of default, including:

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

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

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

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

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

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

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

• the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million that remains undischarged for a period of 60 consecutive days;

• 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.

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

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.

28

Alternative capital resources. We have historically used cash flow from operations, debt financing, and derivative monetizations 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.

29

Results of operations

Comparison of three and six months ended June 30, 2009 to three and six months ended June 30, 2008.

Revenues and production. The following table presents information about our oil and gas sales before the effects of commodity derivative settlements:

	Three months ended June 30,						Six months ended June 30,
	2008		2009		change		2008		2009		change
Oil and gas sales (dollars in thousands)
Oil	$	107,314	$	50,783	(52.7	)%	$	190,327	$	85,896	(54.9	)%
Gas		50,354		18,281	(63.7	)%		88,369		37,035	(58.1	)%
Total	$	157,668	$	69,064	(56.2	)%	$	278,696	$	122,931	(55.9	)%
Production
Oil (MBbls)		931		941	1.1	%		1,823		1,904	4.4	%
Gas (MMcf)		5,117		6,050	18.2	%		9,853		11,687	18.6	%
MMcfe		10,703		11,696	9.3	%		20,791		23,111	11.2	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	115.27	$	53.97	(53.2	)%	$	104.40	$	45.11	(56.8	)%
Gas per Mcf		9.84		3.02	(69.3	)%		8.97		3.17	(64.7	)%
Mcfe		14.73		5.90	(59.9	)%		13.40		5.32	(60.3	)%

Oil and gas revenues decreased by approximately 56% during the three and six months ended June 30, 2009, due to a decrease in average price per Mcfe. Oil and gas prices declined significantly during the first and second quarters of 2009 as compared to the same periods of 2008. Based on our forecasted production, if oil and gas prices remain at current levels or decline further, our revenues in 2009 will be significantly lower than the amounts reported in 2008.

Oil sales decreased 52.7% from $107.3 million during the second quarter of 2008 to $50.8 million during the same period in 2009. This decrease was due to a 53.2% decrease in average oil prices from $115.27 to $53.97 per barrel, partially offset by a 1.1% increase in production volumes to 941 MBbls. Gas sales decreased 63.7% from $50.4 million during the second quarter of June 30, 2008 to $18.3 million during the same period in 2009. This decrease was due to a 69.3% decrease in average gas prices, partially offset by an 18.2% increase in gas production volumes to 6,050 MMcf.

Oil sales decreased 54.9% from $190.3 million during the six months ended June 30, 2008 to $85.9 million during the same period in 2009. This decrease was due to a 56.8% decrease in average oil prices from $104.40 to $45.11 per barrel, partially offset by a 4.4% increase in production volumes to 1,904 MBbls. Gas sales decreased 58.1% from $88.4 million during the six months ended June 30, 2008 to $37.0 million during the same period in 2009. This decrease was due to a 64.7% decrease in average gas prices, partially offset by an 18.6% increase in gas production volumes to 11,687 MMcf.

Production volumes by area were as follows (MMcfe):

	Three months ended June 30,		Percentage		Six months ended June 30,		Percentage
	2008	2009	change		2008	2009	change
Mid Continent	7,050	7,450	5.7	%	13,828	14,784	6.9	%
Permian	2,011	2,691	33.8	%	3,275	5,272	61.0	%
Ark-La-Tex	412	419	1.7	%	900	769	(14.6	)%
North Texas	267	243	(9.0	)%	580	496	(14.5	)%
Rockies	253	198	(21.7	)%	474	389	(17.9	)%
Gulf Coast	710	695	(2.1	)%	1,734	1,401	(19.2	)%
Totals	10,703	11,696	9.3	%	20,791	23,111	11.2	%

Oil and gas production for the three and six months ended June 30, 2009 increased primarily due to our drilling program and enhancements of our existing properties, much of which was accomplished in 2008 and the first quarter of 2009. We have focused our capital expenditures on the Mid Continent and Permian areas. As a result, production in our growth areas has declined and is expected to continue to decline, since our planned capital expenditures for the remainder of 2009 are also focused in our core areas of the Mid Continent and Permian Basin.

        The increase in production in the Permian area is primarily due to the Bowdle 47 No. 2, which began selling gas in late November 2008 and accounted for approximately 11% and 10%, respectively, of total production for the three and six months ended June 30, 2009. We expect production from this well to begin to decline during the third quarter of 2009. Production from the Bowdle 47 No. 2 for the last six months of 2009 is expected to be approximately 75% of its production for the first six months of 2009, and its production in 2010 is expected to be approximately 48% of its total production in 2009. We plan to drill an offset, the Bowdle 47 No. 4, as well as several other high impact wells in the second half of 2009, which, if successful, could maintain our production levels throughout 2010. However, we cannot accurately predict the timing or the level of future production.

Our results of operations, financial condition, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges.

30

During the fourth quarter of 2008, we determined that our gas swaps are no longer expected to be highly effective, primarily due to the increased volatility in the basis differentials between the contract price and the indexed price at the point of sale. As a result, we discontinued hedge accounting and applied mark-to-market accounting treatment to all outstanding gas swaps. The change in fair value related to these instruments, after hedge accounting was discontinued, is recorded immediately in non-hedge derivative gains (losses) in the consolidated statements of operations. In the past, a portion of the change in fair value would have been deferred through other comprehensive income and the ineffective portion would have been included in gain (loss) from oil and gas hedging activities.

In addition, during the fourth quarter of 2008, we monetized oil and gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. During the first quarter of 2009, we monetized additional gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. Certain swaps that were monetized had previously been accounted for as cash flow hedges. As of December 31, 2008 and June 30, 2009, accumulated other comprehensive income included $23.7 million and $86.4 million, respectively, of deferred gains related to discontinued cash flow hedges that will be recognized as a gain from oil and gas hedging activities when the hedged production is sold. No oil and gas derivatives were monetized during the first six months of 2008.

The effects of hedging on our net revenues for the three and six months ended June 30, 2008 and 2009 are as follows:

	Three months ended June 30,						Six months ended June 30,
(dollars in thousands)	2008			2009			2008			2009
Gain (loss) from oil and gas hedging activities:
Receipts from (payments on) hedge settlements	$	(44,994	)	$	(1,699	)	$	(61,257	)	$	2,932
Hedge ineffectiveness and reclassification adjustments		(13,236	)		7,887			(28,098	)		18,759
Total	$	(58,230	)	$	6,188		$	(89,355	)	$	21,691

Primarily as a result of substantially lower oil prices in 2009 than in 2008, payments on hedge settlements were $1.7 million during the second quarter of 2009 compared to $45.0 million during the second quarter of 2008, and receipts from hedge settlements were $2.9 million during the first six months of 2009 compared to payments on hedge settlements of $61.3 million during the first six months of 2008. Gains of $7.9 million and $19.2 million associated with derivatives for which hedge accounting had previously been discontinued, were reclassified into earnings during the three and six months ended June 30, 2009, respectively, as the hedged production was sold. As a result of these transactions, as well as the discontinuance of hedge accounting for all gas swaps discussed above, our gain from oil and gas hedging activities was $6.2 million and $21.7 million during the three and six months ended June 30, 2009 compared to a loss of $58.2 million and $89.4 million for the comparable periods in 2008.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements, excluding early settlements, on realized prices:

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
Oil (per Bbl):
Before derivative settlements	$	115.27		$	53.97		$	104.40		$	45.11
After derivative settlements	$	76.06		$	53.77		$	73.69		$	48.76
Post-settlement to pre-settlement price		66.0	%		99.6	%		70.6	%		108.1	%
Gas (per Mcf):
Before derivative settlements	$	9.84		$	3.02		$	8.97		$	3.17
After derivative settlements	$	7.79		$	4.18		$	7.97		$	4.59
Post-settlement to pre-settlement price		79.2	%		138.4	%		88.9	%		144.8	%

31

Costs and expenses. The following table presents information about our operating expenses for the second quarter of 2008 and 2009:

	Three months ended June 30,				Percent		Six months ended June 30,				Percent
	2008		2009		change		2008		2009		change
Costs and expenses (dollars in thousands)
Lease operating expenses	$	26,367	$	23,557	(10.7	)%	$	53,912	$	50,965	(5.5	)%
Production taxes		10,601		4,941	(53.4	)%		18,516		8,801	(52.5	)%
Depreciation, depletion and amortization		24,934		25,230	1.2	%		48,645		55,400	13.9	%
General and administrative		7,829		5,906	(24.6	)%		14,081		12,274	(12.8	)%
Costs and expenses (per Mcfe)
Lease operating expenses	$	2.46	$	2.01	(18.3	)%	$	2.59	$	2.21	(14.7	)%
Production taxes		0.99		0.42	(57.6	)%		0.89		0.38	(57.3	)%
Depreciation, depletion and amortization		2.33		2.16	(7.3	)%		2.34		2.40	2.6	%
General and administrative		0.73		0.50	(31.5	)%		0.68		0.53	(22.1	)%

Lease operating expenses – Due to higher production mostly associated with the Bowdle 47 No. 2 well and our efforts to reduce production costs, lease operating expenses per Mcfe for the three and six months ended June 30, 2009 declined $0.45 to $2.01 and $0.38 to $2.21, respectively, compared to the same periods in 2008. During the three and six months ended June 30, 2009, electricity and fuel costs decreased by $1.3 million and $1.5 million, respectively, and workovers and other field service costs decreased by $1.4 million and $1.5 million, respectively, compared to the same periods in 2008. Oil prices have recently started to improve, and if this upward trend continues, we expect absolute and per Mcfe operating costs to increase as well.

Production taxes (which include ad valorem taxes) – The decrease for the second quarter of 2009 was primarily due to 59.9% lower average prices, partially offset by a 9.3% increase in production volumes. The decrease for the first six months of 2009 was primarily due to 60.3% lower average prices, partially offset by an 11.2% increase in production volumes.

Depreciation, depletion and amortization (“DD&A”) – The increase for the second quarter of 2009 was primarily due to a $0.8 million increase in depreciation on equipment placed in service during the third quarter of 2008, which was partially offset by a decrease in DD&A on oil and gas properties of $0.5 million. Our DD&A rate on oil and gas properties per equivalent unit of production decreased $0.23 to $1.91 per Mcfe primarily due to the decrease in capitalized costs resulting from our ceiling test impairments recorded in the fourth quarter of 2008 and the first quarter of 2009, combined with lower estimated future development costs. This decrease in the DD&A rate per equivalent unit of production reduced DD&A for oil and gas properties by $2.4 million, which was offset by increased DD&A of $1.9 million due to higher production volumes.

The increase for the first six months of 2009 was primarily due to an increase in DD&A on oil and gas properties of $4.9 million as a result of higher production volumes. Our DD&A rate on oil and gas properties per equivalent unit of production was $2.15 for the first six months of 2009 and 2008.

Impairment of oil and gas properties — In accordance with the full cost method of accounting, the net capitalized costs of oil and gas properties are not to exceed their related estimated future net revenues discounted at 10%, as adjusted for our cash flow hedge positions and net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. During the first quarter of 2009, gas prices declined significantly as compared to the December 31, 2008 spot price of $5.62 per Mcf. Based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of gas, the internally estimated PV-10 value of our reserves declined by 13.5% compared to our PV-10 value at December 31, 2008. As a result, we recorded a ceiling test impairment of oil and gas properties of $240.8 million during the first quarter of 2009. The effect of derivative contracts accounted for as cash flow hedges, based on the March 31, 2009 spot prices, increased the full cost ceiling by $169.0 million, thereby reducing the ceiling test write down by the same amount.

The internally estimated PV-10 value of our reserves was estimated based on spot prices of $69.89 per Bbl of oil and $3.89 per Mcf of gas at June 30, 2009. The effect of derivative contracts accounted for as cash flow hedges, based on these June 30, 2009, spot prices, reduced the full cost ceiling by $12.9 million. The qualifying cash flow hedges as of June 30, 2009, which consisted of commodity price swaps, covered 4,265 MBbls of oil production for the period from July 2009 through December 2011. As of June 30, 2009, the cost center ceiling exceeded the net capitalized cost of our oil and gas properties, and no ceiling test impairment was recorded during the second quarter of 2009.

A decline in oil and gas prices subsequent to June 30, 2009 could result in additional ceiling test write downs in the third quarter of 2009 or in subsequent periods. The amount of any future impairment is difficult to predict, and will depend on the oil and gas prices at the end of or during each period, the incremental proved reserves added during each period, and additional capital spent.

Litigation settlement — Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004,
et al. This case was related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”).

Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7.1 million, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $0.4 million contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4.4 million, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of June 30, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.

32

General and administrative expenses – The decrease was primarily due to lower deferred compensation costs. The value of each unit in our Phantom Stock Plan decreased due to lower commodity prices. As a result, deferred compensation expense decreased by $1.5 million and $1.7 million, respectively, during the three and six months ended June 30, 2009 as compared to the same period of 2008. G&A expense is net of amounts capitalized as part of our exploration and development activities, as shown in the following table:

	Three months ended June 30,						Six months ended June 30,
	2008			2009			2008			2009
General and administrative cost	$	11,950		$	8,601		$	21,339		$	17,829
Less: general and administrative cost capitalized		(4,121	)		(2,695	)		(7,258	)		(5,555	)
General and administrative expense	$	7,829		$	5,906		$	14,081		$	12,274

Interest expense – Interest expense for the three and six months ended June 30, 2009 increased by 7.7% and 6.0%, respectively, compared to the same periods in 2008 primarily as a result of increased levels of borrowings. The following table presents interest expense for the three and six months ended June 30, 2008 and 2009:

	Three months ended June 30,				Six months ended June 30,
(dollars in thousands)	2008		2009		2008		2009
Revolver interest	$	5,498	$	6,920	$	11,569	$	13,772
8  1/2% Senior Notes, due 2015		7,085		7,102		14,166		14,199
8  7/8% Senior Notes, due 2017		7,379		7,397		14,754		14,791
Other interest		1,139		1,301		2,132		2,422
	$	21,101	$	22,720	$	42,621	$	45,184

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

	Three months ended June 30,						Six months ended June 30,
(dollars in thousands)	2008			2009			2008			2009
Change in fair value of non-qualified commodity price swaps	$	(51,058	)	$	(98,665	)	$	(58,880	)	$	(68,753	)
Change in fair value of non-designated costless collars		(8,557	)		(39,331	)		(8,557	)		(36,169	)
Change in fair value of natural gas basis differential contracts		3,119			(5,910	)		4,815			(10,236	)
Receipts from (payments on) settlement of non-qualified commodity price swaps		(3,380	)		84,499			(5,206	)		99,229
Receipts from settlement of non-designated costless collars		—			27,267			—			32,345
Receipts from (payments on) settlement of natural gas basis differential contracts		1,377			(879	)		647			892
	$	(58,499	)	$	(33,019	)	$	(67,181	)	$	17,308

The loss on non-qualified commodity price swaps for the second quarter of 2009 was $14.2 million, and included losses of $12.4 million and $1.8 million on oil and gas swaps, respectively. The gain on non-qualified commodity price swaps for the first six months of 2009 was $30.4 million and included gains of $41.7 million on gas swaps, partially offset by losses of $11.3 million on oil swaps. The loss on non-qualified commodity price swaps for the three and six months ended June 30, 2008 was $54.4 million and $64.1 million respectively, and was comprised of losses on oil swaps that were entered into in anticipation of the Calumet acquisition and did not qualify as hedges.

For the three and six months ended June 30, 2009, the loss on costless collars was $12.0 million and $3.8 million, respectively. Due primarily to higher NYMEX forward strip oil prices at June 30, 2009 compared to March 31, 2009 and December 31, 2008, the loss on oil collars was $12.5 million and $13.0 million, respectively, for the three and six months ended June 30, 2009. This was partially offset by a gain on gas collars of $0.5 million and $9.2 million, respectively, for the three and six months ended June 30, 2009. For the three and six months ended June 30, 2008, the loss on costless collars was $8.6 million and consisted of a loss on oil collars of $3.7 million and a loss on gas collars of $4.9 million.

For the three and six months ended June 30, 2009, the loss on natural gas basis differential contracts was $6.8 million and $9.3 million, respectively, compared to gains of $4.5 million and $5.5 million, respectively, for the comparable periods of 2008, primarily due to lower differentials indicated by the forward commodity price curves. We had basis swaps covering 35,360 BBtu at June 30, 2009 compared to 6,950 BBtu at June 30, 2008.

Primarily as a result of the above transactions, we had non-hedge derivative losses of $33.0 million and $58.5 million, respectively, for the quarters ended June 30, 2009 and 2008, and non-hedge derivative gains of $17.3 million for the first six months of 2009 compared to non-hedge derivative losses of $67.2 million for the comparable period in 2008.

33

Production tax credits – During 2006, we purchased interests in two venture capital limited liability companies resulting in a total investment of $15.0 million. Our return on the investment was the receipt of $2 of Oklahoma tax credits for every $1 invested and was recouped from our Oklahoma production taxes. The investments are accounted for as a production tax benefit asset and are netted against tax credits realized in other income using the effective yield method over the expected recovery period. Other income for the three months ended June 30, 2008 and 2009 includes Oklahoma production tax credits of $0.3 million and $2.6 million, respectively. Other income for the six months ended June 30, 2008 and 2009 includes Oklahoma production tax credits of $0.7 million and $13.5 million, respectively. This source of income will not be available in future periods.

Discontinued Operations – During the second quarter of 2009, we committed to a plan to sell the assets of GCS, a wholly owned subsidiary that provides oilfield supplies, oilfield chemicals, downhole electric submersible pumps, and related services to oil and gas operators primarily in Oklahoma, Texas, and Wyoming.

On May 14, 2009, we entered into an agreement to sell the assets of the ESP Division of GCS to Global for a cash price of $26.0 million, subject to working capital adjustments as provided in the agreement. On June 8, 2009, we received $24.7 million in conjunction with the closing of the ESP Division sale to Global. The amount received reflected a reduction of $1.3 million due to working capital changes as of March 31, 2009. We paid off notes payable attributed to certain assets sold to Global in the amount of $1.6 million. The purchase price is subject to a final working capital adjustment on or before August 27, 2009. As of June 30, 2009, we recorded a pre-tax gain associated with the sale of $9.0 million. All taxable income associated with such gain was offset by existing net operating losses.

The operating results of GCS for the three and six months ended June 30, 2008 and 2009 have been reclassified as discontinued operations in the consolidated statements of operations. Income from discontinued operations, including the gain on the sale of the ESP Division and net of income taxes, was $0.3 million and $5.4 million, respectively, for the second quarter of 2008 and 2009, and $0.5 million and $5.5 million, respectively, for the six months ended June 30, 2008 and 2009.

Non-GAAP financial measures and reconciliations

We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) non-cash deferred compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual, non-cash charges. Any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization are excluded from the calculation of adjusted EBITDA.

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

	Three months ended June 30,						Six months ended June 30,
(Dollars in thousands)	2008			2009			2008			2009
Net loss	$	(30,052	)	$	(17,724	)	$	(33,019	)	$	(142,548	)
Interest expense		21,101			22,720			42,621			45,184
Income tax benefit		(18,737	)		(10,772	)		(20,612	)		(89,178	)
Depreciation, depletion, and amortization		25,275			25,456			49,167			55,899
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments		13,236			(7,887	)		28,098			(18,759	)
Non-cash change in fair value of non-hedge derivative instruments		56,496			41,554			62,622			12,806
Interest income		(85	)		(71	)		(206	)		(172	)
Non-cash deferred compensation expense		2,106			474			2,393			631
Gain on disposed assets		(235	)		(9,004	)		(230	)		(9,005	)
Loss on impairment of oil and gas properties		—			—			—			240,790
Loss on litigation settlement		—			—			—			2,928
Adjusted EBITDA	$	69,105		$	44,746		$	130,834		$	98,576

Critical accounting policies and estimates

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

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.

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

We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with SFAS No. 157, Fair Value Measurements (“SFAS 157”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2 in accordance with SFAS 157. We determine fair value for our oil and gas collars using an option pricing model which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3 in accordance with SFAS 157. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

Oil and gas properties.

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

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

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

• Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10%, adjusted for derivatives accounted for as cash flow hedges, plus the lower of cost or fair market value of unproved 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.

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• 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 judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

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

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

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

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

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

Recent accounting pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and 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 production for the six months ended June 30, 2009, our gross revenues from oil and gas sales would change approximately $1.2 million for each $0.10 change in gas prices and $1.9 million for each $1.00 change in oil prices.

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

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

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. We do not believe that these instruments qualify as hedges pursuant to SFAS 133; therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative gains (losses).

In anticipation of the Calumet acquisition, we entered into additional commodity swaps to provide protection against a decline in the price of oil. We do not believe that these instruments qualify as hedges pursuant to SFAS 133. Therefore, the changes in fair value and settlement of these derivative contracts are recognized as non-hedge derivative losses. Also, as a result of the acquisition, Chaparral assumed the existing Calumet swaps on October 31, 2006, and designated these as cash flow hedges. As of December 31, 2008, the hedges assumed as part of the Calumet acquisition have been settled.

Our outstanding oil and gas derivative instruments as of June 30, 2009, are summarized below:

	Crude oil swaps						Crude oil collars			Percent of PDP production(1)
	Hedge			Non-hedge			Non-hedge
	Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average fixed price to be received		Volume MBbl	Weighted average range to be received
3Q 2009	571	$	67.47	90	$	66.57	60	$	110.00 - $164.28	84.1	%
4Q 2009	553		67.47	90		66.18	60		110.00 -   164.28	84.8	%
1Q 2010	495		67.69	102		65.80	60		110.00 -   168.55	81.6	%
2Q 2010	495		67.62	90		65.47	60		110.00 -   168.55	82.3	%
3Q 2010	468		67.51	90		65.10	60		110.00 -   168.55	80.7	%
4Q 2010	447		66.81	90		64.75	60		110.00 -   168.55	84.5	%
1Q 2011	309		64.40	99		64.24	51		110.00 -   152.71	66.4	%
2Q 2011	309		64.06	90		63.93	51		110.00 -   152.71	66.4	%
3Q 2011	309		63.71	90		63.61	51		110.00 -   152.71	67.8	%
4Q 2011	309		63.33	90		63.30	51		110.00 -   152.71	69.1	%
	4,265			921			564

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

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	Natural gas swaps non-hedge			Natural gas collars non-hedge			Percent of PDP production (1)
	Volume BBtu	Weighted average fixed price to be received		Volume BBtu	Weighted average range to be received
3Q 2009	1,590	$	8.41	990	$	10.00 - $13.85	43.4	%
4Q 2009	2,900		7.91	990		10.00 -   13.85	70.4	%
1Q 2010	3,150		7.73	840		10.00 -   11.53	76.9	%
2Q 2010	3,150		7.05	840		10.00 -   11.53	81.3	%
3Q 2010	3,150		7.27	840		10.00 -   11.53	85.5	%
4Q 2010	3,150		7.69	840		10.00 -   11.53	94.5	%
1Q 2011	2,400		7.91	—		—	59.4	%
2Q 2011	2,400		7.03	—		—	61.8	%
3Q 2011	2,400		7.20	—		—	64.4	%
4Q 2011	2,400		7.55	—		—	66.6	%
	26,690			5,340

	Natural gas basis protection swaps non-hedge
	Volume BBtu	Weighted average fixed price to be paid
3Q 2009	4,620	$	0.91
4Q 2009	4,440		0.94
1Q 2010	4,950		0.94
2Q 2010	3,300		0.80
3Q 2010	3,300		0.80
4Q 2010	3,500		0.80
1Q 2011	3,600		0.80
2Q 2011	2,550		0.75
3Q 2011	2,550		0.75
4Q 2011	2,550		0.75
	35,360

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

Subsequent to June 30, 2009, we entered into additional oil swaps for 260 MBbls for the periods of January 2010 through December 2011 with a weighted average price of $80.26. We also entered into additional gas swaps for 600 BBtu for the periods of January through December 2011 with a weighted average price of $6.76.

Interest rates. All of the outstanding borrowings under our Credit Agreement as of June 30, 2009, 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 greater of (1) the Prime Rate, as defined in our Credit Agreement, (2) the Federal Funds Effective Rate plus ¹ / 2 of 1%, or (3) the Adjusted LIBO rate, as defined in our Credit Agreement. Eurodollar loans bear interest at a fluctuating rate that is linked to the Adjusted LIBO Rate, defined as the greater of 2% or the rate applicable to dollar deposits in the London interbank market. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $513.0 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 $5.1 million.

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ITEM 4. CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the Board of Directors. Based on their evaluation as of the end of the period covered by this quarterly report, our Chairman, President and Chief Executive Officer and our Executive Vice President and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms 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.

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

Effective April 15, 2009, we settled our pending lawsuit against John Milton Graves Trust u/t/a 6/11/2004, et al. This case was filed in the District Court of Tulsa County, State of Oklahoma, and related to (i) a post-closing adjustment of the price we paid for Calumet Oil Company (“Calumet”) in 2006 (the “Working Capital Adjustment”) and (ii) a contractual payment related to an election to be made by the sellers of Calumet (collectively, the “Sellers”) under the federal tax code (the “Tax Election”).

Pursuant to the settlement agreement, which was based upon net calculations of the receivable and payable, the Sellers paid us $7.1 million, which amount is intended to settle all claims related to both the Working Capital Adjustment and the Tax Election claims, and we retained $0.4 million contained in an escrow account covering any losses incurred by us for title defects related to our purchase of Calumet. In addition, the parties issued mutual releases, dismissed with prejudice the pending litigation and the claims made therein, and the Sellers will take action to clear the title to certain properties purchased by us in the Calumet acquisition.

As of December 31, 2008, the recorded receivable for the Working Capital Adjustment was $14.4 million, and was included in other assets on the consolidated balance sheet. As of December 31, 2008, the recorded payable related to the Tax Election was $4.4 million, and was included in accounts payable and accrued liabilities on the consolidated balance sheet. As a result of the settlement, as of June 30, 2009, the receivable related to the Working Capital Adjustment and the Tax Election payable were eliminated, the escrow cash account was reclassified to operating cash, and we recorded a charge to expense of $2.9 million.

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, 2008. There have been no material changes to the risk factors since the filing of such Form 10-K.

ITEM 6. EXHIBITS

Exhibit No.	Description
10.20*	Fifth Amendment to Seventh Restated Credit Agreement dated as of May 21, 2009. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on May 26, 2009)

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Exhibit No.	Description
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* 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: August 13, 2009

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EXHIBIT INDEX

Exhibit No.	Description
10.20*	Fifth Amendment to Seventh Restated Credit Agreement dated as of May 21, 2009. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748), filed on May 26, 2009)

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Exhibit No.	Description
31.1	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
32.1	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Incorporated by reference

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