Chaparral Energy, Inc. - FORM 10-Q

Chaparral Energy, Inc. - FORM 10-Q - August 12, 2011

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EX-32.2 - SECTION 906 CFO CERTIFICATION - Chaparral Energy, Inc.	dex322.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - Chaparral Energy, Inc.	dex321.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - Chaparral Energy, Inc.	dex312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - Chaparral Energy, Inc.	dex311.htm

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, 2011

¨	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 ¨ No x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

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 x 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.

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

Number of shares outstanding of each of the issuer’s classes of common stock as of August 12, 2011:


Class	Number of shares
Class A Common Stock, $0.01 par value		65,981
Class B Common Stock, $0.01 par value		357,882
Class C Common Stock, $0.01 par value		209,882
Class D Common Stock, $0.01 par value		279,999
Class E Common Stock, $0.01 par value		504,276
Class F Common Stock, $0.01 par value		1
Class G Common Stock, $0.01 par value		3

CHAPARRAL ENERGY, INC.

Index to Form 10-Q


	Page
Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated balance sheets as of June 30, 2011 (unaudited) and December 31, 2010		6
Consolidated statements of operations for the three and six months ended June 30, 2011 and 2010 (unaudited)		8
Consolidated statements of cash flows for the six months ended June 30, 2011 and 2010 (unaudited)		9
Notes to consolidated financial statements (unaudited)		11
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Overview		27
Liquidity and capital resources		28
Results of operations		34
Non-GAAP financial measure and reconciliation		42
Critical accounting policies		42
Recent Accounting Pronouncements		42
Item 3. Quantitative and qualitative disclosures about market risk		43
Item 4. Controls and procedures		45
Part II. OTHER INFORMATION		45
Item 1. Legal Proceedings		45
Item 1A. Risk Factors		45
Item 6. Exhibits		46
Signatures		47
EX-31.1 (Certification by CEO required by rule 13a-14(a)/15d-14(a))
EX-31.2 (Certification by CFO required by rule 13a-14(a)/15d-14(a))
EX-32.1 (Certification by CEO pursuant to section 906)
EX-32.2 (Certification by CFO pursuant to section 906)

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities law. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our 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. Any statement that is not an historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of 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 in this report may include, for example, statements about:

•

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

•

the amount, nature and timing of capital expenditures;

•

drilling, completion and performance of wells;

•

competition and government regulations;

•

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

•

costs of exploiting and developing 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 of property acquisitions; and

•

marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. These risks and uncertainties include those factors described under the heading “Risk Factors” in this report and in our Annual Report on Form 10-K filed with the SEC on March 29, 2011. Specifically, some factors that could cause actual results to differ include:

•

the significant amount of our debt;

•

worldwide demand for oil and natural gas;

•

volatility and declines in oil and natural gas prices;

•

drilling plans (including scheduled and budgeted wells);

•

the number, timing or results of any wells;

•

changes in wells operated and in reserve estimates;

•

supply of CO₂;

•

future growth and expansion;

•

future exploration;

•

integration of existing and new technologies into operations;

•

future capital expenditures (or funding thereof) and working capital;

•

borrowings and capital resources and liquidity;

•

changes in strategy and business discipline;

•

future tax matters;

•

any loss of key personnel;

•

future seismic data (including timing and results);

•

the plans for timing, interpretation and results of new or existing seismic surveys or seismic data;

•

geopolitical events affecting oil and natural gas prices;

•

outcome, effects or timing of legal proceedings;

•

the effect of litigation and contingencies;

•

the ability to generate additional prospects; and

•

the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

GLOSSARY OF OIL AND NATURAL 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.

•

Boe. Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

•

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.

•

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

•

MBoe. One thousand barrels of crude oil equivalent.

•

Mcf. One thousand cubic feet of natural gas.

•

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

•

MMBoe. One million barrels of crude oil equivalent.

•

MMcf. One million cubic feet of natural gas.

•

NYMEX. The New York Mercantile Exchange.

•

PDP. Proved developed producing.

•

Proved reserves. The quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

•

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.

•

SEC. The Securities and Exchange Commission.

PART I — FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets


(dollars in thousands, except per share data)	June 30, 2011 (unaudited)			December 31, 2010
Assets
Current assets:
Cash and cash equivalents	$	54,232		$	55,111
Accounts receivable, net		68,580			62,780
Inventories		10,742			11,068
Prepaid expenses		1,263			2,429
Derivative instruments		586			1,429
Deferred income taxes		—			9,531

Total current assets		135,403			142,348
Property and equipment—at cost, net		66,198			66,014
Oil and natural gas properties, using the full cost method:
Proved		2,419,388			2,253,662
Unevaluated (excluded from the amortization base)		24,962			19,135
Accumulated depreciation, depletion, amortization and impairment		(1,067,194	)		(1,003,261	)

Total oil and natural gas properties		1,377,156			1,269,536
Derivative instruments		388			—
Deferred income taxes		23,803			20,617
Other assets		34,924			30,777

	$	1,637,872		$	1,529,292

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

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets - continued


(dollars in thousands, except per share data)	June 30, 2011 (unaudited)			December 31, 2010
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	80,008		$	75,982
Accrued payroll and benefits payable		15,953			13,427
Accrued interest payable		31,066			23,695
Revenue distribution payable		22,069			17,223
Current maturities of long-term debt and capital leases		3,637			4,167
Derivative instruments		20,692			28,853
Deferred income taxes		4,662			—

Total current liabilities		178,087			163,347
Long-term debt and capital leases, less current maturities		16,238			16,686
Senior notes, net		1,016,559			941,234
Derivative instruments		3,912			2,482
Deferred compensation		1,524			981
Asset retirement obligations		42,466			41,005
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—			—
Class A Common stock, $0.01 par value, 10,000,000 shares authorized and 66,704 and 51,346 shares issued and outstanding as of June 30, 2011 and December 31, 2010, respectively		—			—
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 357,882 shares issued and outstanding		4			4
Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding		2			2
Class D Common stock, $0.01 par value, 10,000,000 shares authorized and 279,999 shares issued and outstanding		3			3
Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding		5			5
Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding		—			—
Class G Common stock, $0.01 par value, 3 shares authorized, issued, and outstanding		—			—
Additional paid in capital		417,828			417,834
Accumulated deficit		(82,135	)		(89,265	)
Accumulated other comprehensive income, net of taxes		43,379			34,974

		379,086			363,557

	$	1,637,872		$	1,529,292

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations


	Three months ended June 30,						Six months ended June 30,
(dollars in thousands)	2011 (unaudited)			2010 (unaudited)			2011 (unaudited)			2010 (unaudited)
Revenues:
Oil and natural gas sales	$	146,482		$	96,785		$	274,081		$	197,160
Loss from oil and natural gas hedging activities		(6,806	)		(8,206	)		(13,561	)		(13,191	)
Other revenues		1,060			857			2,205			1,728

Total revenues		140,736			89,436			262,725			185,697
Costs and expenses:
Lease operating		31,748			27,256			59,304			51,675
Production tax		9,456			6,190			18,080			13,180
Depreciation, depletion and amortization		36,877			25,067			70,854			49,588
General and administrative		9,567			7,871			17,575			14,311
Other expenses		827			768			1,909			1,472

Total costs and expenses		88,475			67,152			167,722			130,226
Operating income		52,261			22,284			95,003			55,471
Non-operating income (expense):
Interest expense		(24,221	)		(17,534	)		(47,931	)		(40,086	)
Non-hedge derivative gains (losses)		47,296			39,860			(13,630	)		70,917
Loss on extinguishment of debt		—			(2,241	)		(20,576	)		(2,241	)
Financing costs		—			(1,263	)		—			(1,560	)
Other income and expenses		68			112			115			250

Net non-operating income (expense)		23,143			18,934			(82,022	)		27,280
Income before income taxes		75,404			41,218			12,981			82,751
Income tax expense		28,010			16,340			5,851			32,409

Net income	$	47,394		$	24,878		$	7,130		$	50,342

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows


	Six months ended June 30,
(dollars in thousands)	2011 (unaudited)			2010 (unaudited)
Cash flows from operating activities
Net income	$	7,130		$	50,342
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion & amortization		70,854			49,588
Deferred income taxes		5,851			32,414
Unrealized loss on ineffective portion of hedges and reclassification adjustments		13,561			7,687
Non-hedge derivative (gains) losses		13,630			(70,917	)
Other		1,562			675
Change in assets and liabilities
Accounts receivable		(6,073	)		3,945
Inventories		(24	)		(375	)
Prepaid expenses and other assets		22,831			7,169
Accounts payable and accrued liabilities		16,365			(1,625	)
Revenue distribution payable		4,846			(2,034	)
Deferred compensation		1,597			(490	)

Net cash provided by operating activities		152,130			76,379
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties		(180,875	)		(123,695	)
Proceeds from dispositions of property and equipment and oil and natural gas properties		412			336
Settlement of non-hedge derivative instruments		(19,906	)		25,757
Other		—			16

Net cash used in investing activities		(200,369	)		(97,586	)
Cash flows from financing activities
Proceeds from long-term debt		1,415			172,886
Repayment of long-term debt		(2,293	)		(509,359	)
Proceeds from Senior Notes		400,000			—
Repayment of Senior Notes		(325,000	)		—
Proceeds from equity issuance		—			313,231
Principal payments under capital lease obligations		(100	)		(129	)
Payment of debt issuance costs and other financing fees		(11,577	)		(12,840	)
Payment of debt extinguishment costs		(15,085	)		—

Net cash provided by (used in) financing activities		47,360			(36,211	)

Net decrease in cash and cash equivalents		(879	)		(57,418	)
Cash and cash equivalents at beginning of period		55,111			73,417

Cash and cash equivalents at end of period	$	54,232		$	15,999

Supplemental cash flow information
Cash paid (received) during the period for:
Interest, net of capitalized interest	$	38,372		$	37,436
Income taxes		—			(5	)

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

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows—continued

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

During the six months ended June 30, 2011, oil and natural gas property additions of $4,920 previously included in accounts payable and accrued expenses were settled and are reflected in cash used in investing activities. During the six months ended June 30, 2010, oil and natural gas property additions of $3,196 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, 2011 and 2010, we recorded an asset and related liability of $242 and $191, respectively, associated with the asset retirement obligation on the acquisition and/or development of oil and natural gas properties.

Interest of $1,195 and $757 was capitalized during the six months ended June 30, 2011 and 2010, respectively, primarily related to unproved oil and natural gas leaseholds.

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 natural 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 the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2010.

The financial information as of June 30, 2011, and for the three and six months ended June 30, 2011 and 2010, is unaudited. In management’s opinion, 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, 2011, are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2011.

Reclassifications

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

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, 2011, cash with a recorded balance totaling $51,430 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.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. Interest accrues beginning on the day after the due date of the receivable. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. When the account is determined to be uncollectible, all interest previously accrued but not collected is reversed against the allowance for doubtful accounts. Accounts receivable consisted of the following at June 30, 2011 and December 31, 2010:


	June 30, 2011			December 31, 2010
Joint interests	$	20,579		$	17,835
Accrued oil and natural gas sales		47,847			41,316
Derivative settlements		159			3,431
Other		736			831
Allowance for doubtful accounts		(741	)		(633	)

	$	68,580		$	62,780

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural 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 natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. Inventories at June 30, 2011 and December 31, 2010 consisted of the following:


	June 30, 2011			December 31, 2010
Equipment inventory	$	6,657		$	6,399
Oil and natural gas product		3,493			3,624
Inventory for resale		2,757			2,866
Inventory valuation allowance		(2,165	)		(1,821	)

	$	10,742		$	11,068

Fair value measurements

Fair value is defined by the Financial Accounting Standards Board (“FASB”) as 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.

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

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

Stock-based compensation

Our stock-based compensation programs consist of phantom stock and restricted stock awards issued to employees. The estimated fair value of the phantom stock awards is remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan. The primary adjustment required is the adjustment of oil and natural 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 cost associated with the phantom stock awards is recognized on a straight-line basis over the five-year vesting period.

The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common stock on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. These assumptions reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

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. During the six months ended June 30, 2011, we recorded a valuation allowance of $1,449 for state NOL carryforwards we do not expect to realize before they expire.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

Recently issued accounting pronouncements

In May 2011, the FASB issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we will adopt it on January 1, 2012. We are currently evaluating the provisions of this guidance and its anticipated impact on our fair value disclosures.

In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we will apply it retrospectively beginning on January 1, 2012. We are currently evaluating the provisions of this guidance and its anticipated impact on our presentation of other comprehensive income.

Note 2: Derivative activities and financial instruments

Overview

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. See Note 1 for additional information regarding our accounting policies for fair value measurements.

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. A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the floor price of the collar. This additional put option requires us to make a payment to the counterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.

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 natural 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.

Our outstanding derivative instruments as of June 30, 2011 are summarized below:


	Oil derivatives
	Swaps				Collars				Three-way collars
	Volume MBbls		Weighted average		Volume MBbls		Weighted average range		Volume MBbls		Weighted average fixed price per Bbl
	Volume MBbls		fixed price per Bbl		Volume MBbls		(fixed price per Bbl)		Volume MBbls		Additional put option		Floor		Ceiling

2011		1,606	$	77.58		42	$	110.00 - $153.00		—	$	—	$	—	$	—
2012		1,983		94.08		—		—		840		67.14		90.00		110.26
2013		540		102.45		—		—		1,080		73.33		97.22		126.00

		4,129				42				1,920


	Natural gas swaps				Natural gas basis protection swaps
	Volume BBtu		Weighted average fixed price per Btu		Volume BBtu		Weighted average fixed price per Btu
2011		9,580	$	6.28		7,330	$	0.64
2012		12,000		5.06		8,400		0.30
2013		7,200		5.24		—		—

		28,780				15,730

Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility, and we believe the credit risks associated with all of these institutions are acceptable. As of June 30, 2011 we have no balance outstanding on our credit facility. We did not post collateral under any of these contracts as they are secured under our revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our revolving credit facility. The aggregate fair value of our derivative liabilities was $47,660 at June 30, 2011.

Discontinuance of cash flow hedge accounting

Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Prior to March 31, 2010, a portion of the change in fair value was deferred through other comprehensive income. As of June 30, 2011, accumulated other comprehensive income (“AOCI”) consists of deferred net gains of $69,989 ($43,379 net of tax) that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold. We expect to reclassify $6,457 of net gains in AOCI to income during the next 12 months.

Derivative activities

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


	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Amount of loss recognized in AOCI (effective portion)
Oil swaps	$	—		$	—		$	—		$	(1,035	)
Income taxes		—			—			—			400

	$	—		$	—		$	—		$	(635	)

Amount of gain (loss) reclassified from AOCI in income (effective portion)(1)
Oil swaps	$	(6,806	)	$	(8,551	)	$	(13,561	)	$	(13,395	)
Natural gas swaps		—			345			—			864
Income taxes		2,588			3,174			5,156			4,847

	$	(4,218	)	$	(5,032	)	$	(8,405	)	$	(7,684	)


Loss on oil swaps recognized in income (ineffective portion)(1)	$	—		$	—		$	—		$	(660	)

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

Loss from oil and natural 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,
	2011			2010			2011			2010
Oil hedges
Reclassification adjustment for hedge losses included in net income	$	(6,806	)	$	(8,551	)	$	(13,561	)	$	(13,395	)
Loss on ineffective portion of derivatives qualifying for hedge accounting		—			—			—			(660	)
Natural gas hedges
Reclassification adjustment for hedge gains included in net income		—			345			—			864

	$	(6,806	)	$	(8,206	)	$	(13,561	)	$	(13,191	)

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,
	2011			2010			2011			2010
Change in fair value of commodity price swaps	$	55,176		$	29,063		$	5,008		$	52,828
Change in fair value of costless collars		5,934			(12,967	)		(671	)		(15,163	)
Change in fair value of natural gas basis differential contracts		798			5,743			1,939			7,495
Receipts from (payments on) settlement of commodity price swaps		(13,060	)		6,346			(16,342	)		12,780
Receipts from settlement of costless collars		156			13,725			490			19,466
Payments on settlement of natural gas basis differential contracts		(1,708	)		(2,050	)		(4,054	)		(6,489	)

	$	47,296		$	39,860		$	(13,630	)	$	70,917

Fair value of derivative instruments

All derivative financial instruments are recorded on the balance sheet at fair value. We estimate the fair value of our derivative instruments using a combined income and market valuation methodology. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate. The fair value of collars is determined using an option pricing model which takes into account market volatility as well as the inputs described above. All derivative instruments are discounted further using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ nonperformance risk for derivative assets. As of June 30, 2011 and December 31, 2010, the rate reflecting our nonperformance risk was 2.25% and 2.50%, respectively. The weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 0.40% and 2.14% as of June 30, 2011 and December 31, 2010, respectively.

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 June 30, 2011								As of December 31, 2010
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Derivatives not designated as hedging instruments:
Natural gas swaps	$	20,695	$	(112	)	$	20,583		$	32,538	$	(130	)	$	32,408
Oil swaps		2,497		(43,864	)		(41,367	)		21		(58,221	)		(58,200	)
Oil collars		838		—			838			1,509		—			1,509
Natural gas basis differential swaps		—		(3,684	)		(3,684	)		220		(5,843	)		(5,623	)

Total derivative instruments		24,030		(47,660	)		(23,630	)		34,288		(64,194	)		(29,906	)
Less:
Netting adjustments (1)		23,056		(23,056	)		—			32,859		(32,859	)		—
Current portion asset (liability)		586		(20,692	)		(20,106	)		1,429		(28,853	)		(27,424	)

	$	388	$	(3,912	)	$	(3,524	)	$	—	$	(2,482	)	$	(2,482	)

(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.

Derivative settlements outstanding at June 30, 2011 and December 31, 2010 were as follows:


	June 30, 2011		December 31, 2010
Derivative settlements receivable included in accounts receivable	$	159	$	3,431
Derivative settlements payable included in accounts payable and accrued liabilities	$	8,637	$	785

We have no Level 1 assets or liabilities as of June 30, 2011. Our derivative contracts classified as Level 2 are valued using NYMEX forward commodity price curves and quotations provided by price index developers such as Platts. 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 is shown by the following table:


	As of June 30, 2011									As of December 31, 2010
	Derivative assets			Derivative liabilities			Net assets (liabilities)			Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	23,192		$	(47,660	)	$	(24,468	)	$	32,779		$	(64,194	)	$	(31,415	)
Significant unobservable inputs (Level 3)		838			—			838			1,509			—			1,509
Netting adjustments (1)		(23,056	)		23,056			—			(32,859	)		32,859			—

	$	974		$	(24,604	)	$	(23,630	)	$	1,429		$	(31,335	)	$	(29,906	)

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

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


	For the six months ended June 30,
Net derivative assets	2011			2010
Beginning Balance	$	1,509		$	26,355
Realized and unrealized gains (losses) included in non-hedge derivative gains (losses)		(181	)		4,303
Settlements received		(490	)		(19,466	)

Ending balance		838			11,192


Gains relating to assets still held at the reporting date included in non-hedge derivative gains (losses) for the period	$	64		$	1,928

Fair value of other financial instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at June 30, 2011 and December 31, 2010 approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms. The carrying value and estimated market value of our Senior Notes at June 30, 2011 and December 31, 2010 were as follows:


	June 30, 2011				December 31, 2010
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
8.5% Senior Notes due 2015	$	—	$	—	$	325,000	$	332,313
8.875% Senior Notes due 2017		323,218		336,375		323,099		329,875
9.875% Senior Notes due 2020		293,341		324,750		293,135		315,000
8.25% Senior Notes due 2021		400,000		404,760		—		—

	$	1,016,559	$	1,065,885	$	941,234	$	977,188

Fair value amounts have been estimated based on quoted market prices. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Note 3: Long-term debt

Long-term debt

Long-term debt at June 30, 2011 and December 31, 2010, consisted of the following:


	June 30, 2011		December 31, 2010
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 3.71% to 9.26%, due January 2017 through December 2028; collateralized by real property	$	12,796	$	13,024
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 9.25%, due July 2011 through June 2016; collateralized by automobiles, machinery and equipment		7,049		7,699

		19,845		20,723
Less current maturities		3,607		4,047

	$	16,238	$	16,676

In April 2010, we entered into an Eighth Restated Credit Agreement (“our senior secured revolving credit facility”), which is collateralized by our oil and gas properties. Availability under our senior secured revolving credit facility 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 between each scheduled redetermination and in the event of early termination of our derivative contracts. Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

The Fourth Amendment to our senior secured revolving credit facility, effective April 1, 2011, extended the maturity of our senior secured revolving credit facility from April 12, 2014 to April 1, 2016 and reaffirmed the borrowing base at $375,000 through November 1, 2011. It also amended the definition of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than:

•

4.50 to 1.0 for each period of four consecutive fiscal quarters ending on or prior to December 31, 2011; and

•

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2012 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of June 30, 2011.

Our senior secured revolving credit facility 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 our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility 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.

As of June 30, 2011, we had no balance outstanding under our senior secured revolving credit facility. As of August 12, 2011, we have drawn down $20,000 under our senior secured revolving credit facility.

Senior Notes

On February 22, 2011, we issued $400,000 aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. Interest is payable on the 8.25% Senior Notes semi-annually on March 1 and September 1 each year beginning September 1, 2011. On or after September 1, 2016, we may, at our option, redeem the 8.25% Senior Notes at the following redemption prices plus accrued and unpaid interest: 104.125% after September 1, 2016, 102.750% after September 1, 2017, 101.375% after September 1, 2018, and 100% after September 1, 2019. Prior to March 1, 2014, we may redeem up to 35% of the 8.25% Senior Notes with the net proceeds of one or more equity offerings at a redemption price of 108.250%, plus accrued and unpaid interest.

In connection with the issuance of the 8.25% Senior Notes, we capitalized $8,785 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. We had unamortized issuance costs of $8,601 as of June 30, 2011 that are included in other assets. Amortization of $184 was charged to interest expense during the six months ended June 30, 2011 related to the issuance costs.

During the first half of 2011, we recorded a $20,576 loss associated with the refinancing of our 8.5% Senior Notes due 2015, including $15,085 in repurchase or redemption-related fees and a $5,491 write off of deferred financing costs.

Senior Notes at June 30, 2011 and December 31, 2010 consisted of the following:


	June 30, 2011			December 31, 2010
8.5% Senior Notes due 2015	$	—		$	325,000
8.875% Senior Notes due 2017		325,000			325,000
9.875% Senior Notes due 2020		300,000			300,000
8.25% Senior Notes due 2021		400,000			—
Discount on Senior Notes due 2017		(1,782	)		(1,901	)
Discount on Senior Notes due 2020		(6,659	)		(6,865	)

	$	1,016,559		$	941,234

The indentures governing our Senior Notes contain certain covenants which limit our ability to:

•

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

•

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

•

make investments;

•

create liens on assets;

•

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

•

transfer or sell assets;

•

engage in transactions with affiliates;

•

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

•

enter into other lines of business.

Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Oklahoma Ethanol, LLC and Chaparral Biofuels, LLC.

Note 4: Asset retirement obligations

Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first six months of 2011 were escalated using an annual inflation rate of 2.95%, and discounted using our credit-adjusted risk-free interest rate of 8.3%.These estimates may change based upon future inflation rates and changes in statutory remediation rules.

The following table provides a summary of our asset retirement obligation activity during the six months ended June 30, 2011.


	Six months ended June 30, 2011
Beginning balance	$	41,695
Liabilities incurred in current period		242
Liabilities settled in current period		(550	)
Accretion expense		1,769

		43,156
Less current portion		690

	$	42,466

See Note 1 for additional information regarding our accounting policies for fair value measurements.

Note 5: Stockholders’ equity

Common stock

The following is a summary of the changes in our common shares outstanding during the first half of 2011:


	Common Stock
	Class A			Class B		Class C		Class D		Class E		Class F		Class G		Total
Shares issued at January 1, 2011		51,346			357,882		209,882		279,999		504,276		1		3		1,403,389
Restricted stock issuances		16,494			—		—		—		—		—		—		16,494
Restricted stock forfeitures		(1,136	)		—		—		—		—		—		—		(1,136	)

Shares issued at June 30, 2011		66,704			357,882		209,882		279,999		504,276		1		3		1,418,747

Comprehensive income

Components of comprehensive income, net of related tax, are as follows for the three and six months ended June 30, 2011 and 2010:


	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
Net income	$	47,394	$	24,878	$	7,130	$	50,342
Unrealized loss on hedges		—		—		—		(635	)
Reclassification adjustment for hedge losses included in net income		4,218		5,032		8,405		7,684

Comprehensive income	$	51,612	$	29,910	$	15,535	$	57,391

Note 6: Stock-based compensation

Phantom Stock Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second 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 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. A summary of our phantom stock activity during the first half of 2011 is presented in the following table:


	Weighted average grant date fair value		Phantom shares			Vest date fair value		Weighted average amortization period remaining
	($ per share)							(years)
Unvested and outstanding at January 1, 2011	$	16.04		126,859					2.09
Granted	$	17.85		29,297
Vested	$	17.93		(15,651	)	$	279
Forfeited	$	17.57		(11,547	)

Unvested and outstanding at June 30, 2011	$	16.09		128,958					1.66

Payments of $276 and $1,357 for phantom shares were made during the six months ended June 30, 2011 and 2010, respectively. As of June 30, 2011, there were 196 vested units outstanding with a weighted average fair value of $17.85 per share, and an aggregate intrinsic value of $3, which is included in accrued payroll and benefits payable. Based on an estimated fair value of $21.43 per phantom share as of June 30, 2011, the aggregate intrinsic value of the unvested phantom shares outstanding was $2,764, which includes approximately $1,339 of unrecognized compensation cost that is expected to be recognized over a weighted-average period of 1.66 years. As of June 30, 2011 and December 31, 2010, accrued payroll and benefits payable included $597 and $321, respectively, for deferred compensation costs vesting within the next twelve months.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

These awards consist of shares that are subject to service vesting conditions (the “Time Vesting” awards) and shares that are subject to market and performance vesting conditions (the “Performance Vesting” awards). The Time Vesting awards vest in equal annual installments over the five year vesting period but may also vest on an accelerated basis in the event of a Transaction (as defined in the 2010 Plan). The Performance Vesting awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan.

Effective June 28, 2011, our board of directors modified the terms of the Time Vesting awards to allow all participants in the 2010 Plan to elect, upon vesting of their Time Vesting awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. This modification changed the classification of the Time Vesting awards from equity to liability awards and resulted in a reclassification from additional paid-in capital to accrued payroll and benefits payable of $1,945 and deferred compensation of $695. These awards will be re-measured to fair value at the end of each reporting period. Because the modification did not affect the fair value of the awards or the number of awards expected to vest, no incremental compensation cost was recorded as a result of the modification.

A summary of our Time Vesting restricted stock activity during the first half of 2011 is presented in the following table:


	Time Vesting
	Weighted average grant date fair value		Restricted shares			Vest date fair value
	($ per share)
Unvested and outstanding at January 1, 2011	$	684.15		10,049
Granted		682.84		3,743
Vested		684.15		(1,893	)	$	1,273
Forfeited		684.15		(288	)

Unvested and total outstanding at June 30, 2011	$	683.73		11,611

A summary of our Performance Vesting restricted stock activity during the first half of 2011 is presented in the following table:


	Performance Vesting
	Weighted average grant date fair value		Restricted shares
	($ per share)
Unvested and outstanding at January 1, 2011	$	295.10		41,297
Granted		307.00		12,751
Vested		—		—
Forfeited		295.10		(848	)

Unvested and total outstanding at June 30, 2011	$	297.95		53,200

We expect to repurchase approximately 1,000 of the vested restricted shares during the next twelve months.

Unrecognized compensation cost of approximately $18,760 associated with our non-vested restricted stock awards is expected to be recognized over a weighted-average period of 4.0 years.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. A portion of stock-based compensation cost associated with our employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period. We recognized stock-based compensation expense as follows for the periods indicated:


	Three months ending						Six months ending
	June 30, 2011			June 30, 2010			June 30, 2011			June 30, 2010
Stock-based compensation cost	$	1,362		$	1,059		$	3,037		$	1,312
Less: stock-based compensation cost capitalized		(555	)		(358	)		(1,164	)		(445	)

Stock-based compensation expense	$	807		$	701		$	1,873		$	867

Note 7: Related party transactions

CHK Holdings L.L.C., an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), owns approximately 20% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:


	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Revenues	$	1,185		$	1,578		$	2,462		$	2,929
Joint interest billings	$	(278	)	$	(1,783	)	$	(536	)	$	(4,373	)

In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:


	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Revenues	$	(958	)	$	(489	)	$	(1,419	)	$	(893	)
Joint interest billings	$	1,293		$	273		$	3,059		$	457

Amounts receivable from and payable to Chesapeake at June 30, 2011 and December 31, 2010 were as follows:


	June 30, 2011		December 31, 2010
Amounts receivable from Chesapeake	$	835	$	718
Amounts payable to Chesapeake	$	137	$	120

Note 8: Commitments and contingencies

Standby letters of credit (“Letters”) available under our revolving credit line are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 as of June 30, 2011 and December 31, 2010. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the six months ended June 30, 2011 or 2010.

Naylor Farms, Inc. v. Chaparral Energy, L.L.C.

On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5,000. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied the allegations and are aggressively defending the case. The case is in the initial stages of discovery and has not yet been set for trial. As such, we are not yet able to estimate what impact, if any, the action will have on our financial condition, results of operations, or cash flows.

In our opinion, there are no other material pending legal proceedings to which we 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. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

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 natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2010, we reorganized our oil and natural gas assets into enhanced oil recovery (“EOR”) project areas and conventional (non-EOR) productive basins. Our primary areas of operation using conventional recovery methods are the Anadarko Basin Area, Central Oklahoma Area, and the Permian Basin Area. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“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 natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Generally our producing properties have declining production rates. Our reserve estimates as of December 31, 2010 reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 16%, 12% and 10% for the next three years. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

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

•

cash flow available for capital expenditures;

•

ability to borrow and raise additional capital;

•

ability to service debt;

•

quantity of oil and natural gas we can produce;

•

quantity of oil and natural gas reserves; and

•

operating results for oil and natural gas activities.

During the second quarter of 2011, quarterly production was 2,199 MBoe, a 7% increase from production levels in the second quarter of 2010, primarily due to our recent drilling activity. This increase in production, combined with a 41% increase in our average sales price before hedging, resulted in a 51% increase in revenue from oil and natural gas sales in the second quarter of 2011 compared to the same period in 2010, partially offset by a corresponding increase in operating costs of 32% for the same period. As a result of these and other factors, we reported net income of $47.4 million during the second quarter of 2011 compared to net income of $24.9 million for the comparable period in 2010.

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

•

8.25% Senior Notes due 2021. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately $20.6 million of refinancing costs, including a $5.5 million non-cash write off of deferred financing costs.

•

Capital expenditure budget. We have expanded our 2011 oil and natural gas property capital expenditures budget, reflecting an increased amount of cash available from higher oil prices as well as expected proceeds from asset sales, primarily our previously announced Rocky Mountain divestiture. Our expanded 2011 capital budget allocates $227.0 million to conventional oil and natural gas exploration and production activities. The remaining $93.0 million, or 29%, of the capital budget is allocated to the development of our EOR assets, and represents a substantial increase in capital being directed toward development of our EOR assets as compared to prior years. The increased focus on EOR reduces near term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near term growth with developmental drilling and long term growth through EOR development.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. As of June 30, 2011, we had cash and cash equivalents of $54.2 million and availability of $374.1 million under our senior secured revolving credit facility with a borrowing base of $375.0 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, capital requirements and contingencies for the next 12 months.

We pledge our producing oil and natural gas properties to secure our senior secured revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds to supplement our operating cash flows as a financing source for our capital expenditures. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.

Sources and uses of cash.

Our net decrease in cash is summarized as follows:


	Six months ended June 30,
(dollars in thousands)	2011			2010
Cash flows provided by operating activities	$	152,130		$	76,379
Cash flows used in investing activities		(200,369	)		(97,586	)
Cash flows provided by (used in) financing activities		47,360			(36,211	)

Net decrease in cash during the period	$	(879	)	$	(57,418	)

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. Cash flows from operating activities increased by 99% from 2010 to 2011, primarily due to a 28% increase in the average price received and a 9% increase in production.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the six months ended June 30, 2011 and 2010, cash flows provided by operating activities were approximately 84% and 62%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties.

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


	Six months ended June 30, 2011
(dollars in thousands)	Acquisitions		Drilling		Enhancements		Total		Percent of total			Budgeted 2011 capital expenditures		Percent of total
Enhanced Oil Recovery Project Areas (1)	$	902	$	15,384	$	26,217	$	42,503		24	%	$	93,000		29	%
Anadarko Basin Area		4,206		55,710		2,134		62,050		35	%		100,000		31	%
Central Oklahoma Area		1,327		18,711		5,454		25,492		15	%		57,000		18	%
Permian Basin Area		525		13,340		3,201		17,066		10	%		39,000		12	%
Other		779		21,325		6,351		28,455		16	%		31,000		10	%

Total	$	7,739	$	124,470	$	43,357	$	175,566		100	%	$	320,000		100	%

(1)

Drilling includes $0.2 million of additions relating to conventional assets located in our EOR Project Areas and $2.4 million for CO₂ support facilities and pipelines. Enhancements includes $1.0 million of additions relating to conventional assets located in our EOR Project Areas and $2.9 million for CO₂ support facilities and pipelines.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $5.4 million for property and equipment during the first six months of 2011.

During the first half of 2011, we made net derivative settlement payments totaling $19.9 million. During the first half of 2010, we received net non-hedge derivative settlement payments totaling $25.8 million, including proceeds from early monetization of $7.1 million. Primarily as a result of our capital investments and derivative settlements, cash flows used in investing activities were $200.4 million and $97.6 million during the six months ended June 30, 2011 and 2010, respectively.

Cash flows provided by financing activities were $47.4 million during the first half of 2011. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we paid approximately $8.8 million of issuance costs related to underwriting and other fees and approximately $15.1 million of repurchase and redemption-related costs.

Cash flows used in financing activities were $36.2 million during the first half of 2010. On April 12, 2010, we sold an aggregate of 475,043 shares of our common stock to CCMP for proceeds of $313.2 million, net of fees and other expenses of $11.8 million, and we entered into and closed an Eighth Restated Credit Agreement. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing under our Seventh Restated Credit Agreement.

Credit Agreements

In April 2010, we entered into our senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and, following a recent amendment, matures on April 1, 2016. Availability under our senior secured revolving credit facility 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 between each scheduled redetermination and in the event of early termination of our derivative contracts. Effective April 1, 2011, the borrowing base was reaffirmed at $375.0 million, and our next borrowing base redetermination is scheduled for November 1, 2011.

Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin where the margin varies from 1.75% to 2.75% depending on the utilization percentage of the conforming borrowing base. From April 1, 2011 until October 1, 2011, the margin will be fixed at 2.25%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%; plus a margin where the margin varies from 0.75% to 1.75%, depending on the utilization percentage of the borrowing base.

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

Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:

•

incur additional indebtedness;

•

create or incur additional liens on our oil and natural 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 or terminate certain swap agreements;

•

amend our organizational documents; 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 senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, 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 senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At June 30, 2011 and December 31, 2010, our current ratio as computed using GAAP was 0.76 and 0.87, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 3.35 and 3.78, 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)	June 30, 2011			December 31, 2010
Current assets per GAAP	$	135,403		$	142,348
Plus—Availability under senior secured revolving credit facility		374,080			374,080
Less—Short-term derivative instruments		(586	)		(1,429	)
Less—Deferred tax asset on derivative instruments and asset retirement obligations		—			(9,655	)

Current assets as adjusted	$	508,897		$	505,344

Current liabilities per GAAP	$	178,087		$	163,347
Less—Short term derivative instruments		(20,692	)		(28,853	)
Less— Short-term asset retirement obligation		(690	)		(690	)
Less— Deferred tax liability on derivative instruments and asset retirement obligations		(4,767	)		—

Current liabilities as adjusted	$	151,938		$	133,804

Current ratio for loan compliance		3.35			3.78

In April 2011, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility, as amended, requires us to maintain a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than:

•

4.50 to 1.0 for each period of four consecutive fiscal quarters ending on or prior to December 31, 2011; and

•

Our senior secured revolving credit facility also specifies events of default, including:

•

our failure to pay principal or interest under our senior secured revolving credit facility 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 our senior secured revolving credit facility;

•

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 a voluntary or 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 our senior secured revolving credit facility); 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 the outstanding borrowings under our senior secured revolving credit facility 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 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

Senior Notes

On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately $20.6 million of refinancing costs, including a $5.5 million non-cash write off of deferred financing costs.

The Senior Notes, which include our 8.875% Senior Notes, our 9.875% Senior Notes, and our 8.25% Senior Notes, are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our material existing and future domestic restricted subsidiaries, as defined in the indenture.

On or after the date that is five years before the maturity date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

Prior to the date that is five years before the maturity date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indenture.

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

•

incur or guarantee additional debt, or issue preferred stock;

•

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

•

make investments;

•

incur liens;

•

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

•

engage in transactions with our affiliates;

•

sell assets, including capital stock of our subsidiaries;

•

consolidate, merge or transfer assets; and

•

enter into other lines of business.

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

Alternative capital resources

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

Results of operations

Revenues and production.

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


	Three months ended June 30,				Percentage change			Six months ended June 30,				Percentage change
	2011		2010		Percentage change			2011		2010		Percentage change
Oil and natural gas sales (dollars in thousands)
Oil	$	120,123	$	71,373		68.3	%	$	225,876	$	142,813		58.2	%
Natural gas		26,359		25,412		3.7	%		48,205		54,347		(11.3	)%

Total	$	146,482	$	96,785		51.3	%	$	274,081	$	197,160		39.0	%

Production
Oil (MBbls)		1,252		979		27.9	%		2,456		1,953		25.8	%
Natural gas (MMcf)		5,682		6,420		(11.5	)%		10,830		11,784		(8.1	)%

MBoe		2,199		2,049		7.3	%		4,261		3,917		8.8	%
Average sales prices (excluding derivative settlements)
Oil per Bbl	$	95.94	$	72.90		31.6	%	$	91.97	$	73.12		25.8	%
Gas per Mcf	$	4.64	$	3.96		17.2	%	$	4.45	$	4.61		(3.5	)%

Boe	$	66.61	$	47.24		41.0	%	$	64.32	$	50.33		27.8	%

Oil and natural gas revenues increased $49.7 million, or 51%, during the second quarter of 2011 compared to the second quarter of 2010 due to a 41% increase in the average price per Boe combined with a 7% increase in sales volumes. Oil production for the second quarter of 2011 increased compared to the second quarter of 2010 primarily due to our recent drilling activity. Gas production for the second quarter of 2011 decreased compared to the second quarter of 2010 primarily due to the decline in production in the Haley area of our Permian Basin Area, which accounted for approximately 5% and 10% of total production during the second quarter of 2011 and 2010, respectively.

Oil and natural gas revenues increased $76.9 million, or 39%, during the first half of 2011 compared to the first half of 2010 due to a 28% increase in the average price per Boe combined with a 9% increase in sales volumes. Oil production for the first half of 2011 increased compared to the first half of 2010 primarily due to our recent drilling activity. Gas production for the first half of 2011 decreased compared to the first half of 2010 primarily due to the decline in production in the Haley area of our Permian Basin Area, which accounted for approximately 5% and 9% of total production during the first half of 2011 and 2010, respectively.

The relative impact of changes in commodity prices and sales volumes on our oil and natural gas sales before the effects of hedging is shown in the following table:


	Three months ended June 30, 2011 vs. 2010						Six months ended June 30, 2011 vs. 2010
(dollars in thousands)	Sales change			Percentage change in sales			Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	28,847			40.4	%	$	46,281			32.4	%
Production		19,903			27.9	%		36,782			25.8	%

Total change in oil sales	$	48,750			68.3	%	$	83,063			58.2	%


Change in natural gas sales due to:
Prices	$	3,868			15.2	%	$	(1,742	)		(3.2	)%
Production		(2,921	)		(11.5	)%		(4,400	)		(8.1	)%

Total change in natural gas sales	$	947			3.7	%	$	(6,142	)		(11.3	)%

Production volumes by area were as follows (MBoe):


	Three months ended June 30,				Percentage change			Six months ended June 30,				Percentage change
	2011		2010		Percentage change			2011		2010		Percentage change
Enhanced Oil Recovery Project Areas		282		269		4.8	%		557		529		5.3	%
Anadarko Basin Area		807		652		23.8	%		1,490		1,232		20.9	%
Central Oklahoma Area		486		483		0.6	%		954		952		0.2	%
Permian Basin Area		319		387		(17.6	)%		662		726		(8.8	)%
Other		305		258		18.2	%		598		478		25.1	%

Total		2,199		2,049		7.3	%		4,261		3,917		8.8	%

The increase in production in the Anadarko Basin Area is primarily due to our drilling activity in the Area. Five of our Anadarko Basin Area wells, which came online during the fourth quarter of 2010 and the first quarter of 2011, accounted for approximately 7% of our total production during the three and six months ended June 30, 2011.

The decrease in production in the Permian Basin Area is primarily due the natural decline in production from wells in the Haley area, which accounted for approximately 5% and 10% of total production during the second quarter of 2011 and 2010, respectively, and for approximately 5% and 9% of total production during the first half of 2011 and 2010, respectively. Due to prevailing low natural gas prices, we have reduced our capital expenditures for gas projects during 2011.

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 natural 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.

Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.

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 derivative monetizations, on realized prices:


	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011			2010
Oil (per Bbl):
Before derivative settlements	$	95.94		$	72.90		$	91.97		$	73.12
After derivative settlements	$	79.49		$	71.50		$	77.64		$	69.89
Post-settlement to pre-settlement price		82.9	%		98.1	%		84.4	%		95.6	%

Natural gas (per Mcf):
Before derivative settlements	$	4.64		$	3.96		$	4.45		$	4.61
After derivative settlements	$	5.69		$	5.87		$	5.86		$	6.26
Post-settlement to pre-settlement price		122.6	%		148.2	%		131.7	%		135.8	%

The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


(dollars in thousands)	June 30, 2011			December 31, 2010
Derivative assets (liabilities):
Natural gas swaps	$	20,583		$	32,408
Oil swaps		(41,367	)		(58,200	)
Oil collars		838			1,509
Natural gas basis differential swaps		(3,684	)		(5,623	)

Net derivative liability	$	(23,630	)	$	(29,906	)

Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains (losses) in the consolidated statement of operations. As of June 30, 2011, accumulated other comprehensive income (“AOCI”) consists of deferred net gains of $70.0 million ($43.4 million net of tax) related to discontinued cash flow hedges that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

The effects of derivative activities on our results of operations and cash flows for the second quarters of 2011 and 2010 were as follows:


	Three months ended June 30,
	2011						2010
(dollars in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Loss from oil and natural gas hedging activities:
Oil swaps	$	(6,806	)	$	—		$	(8,551	)	$	—
Natural gas swaps		—			—			345			—

Loss from oil and natural gas hedging activities	$	(6,806	)	$	—		$	(8,206	)	$	—


Non-hedge derivative gains (losses):
Oil swaps and collars	$	61,856		$	(20,596	)	$	34,779		$	(1,374	)
Natural gas swaps and collars		(746	)		7,692			(18,876	)		14,348
Natural gas basis differential contracts		798			(1,708	)		5,743			(2,050	)
Derivative monetizations		—			—			193			7,097

Non-hedge derivative gains (losses)	$	61,908		$	(14,612	)	$	21,839		$	18,021

Total gains (losses) from derivative activities	$	55,102		$	(14,612	)	$	13,633		$	18,021

Due primarily to a decrease in average NYMEX forward strip oil prices as of June 30, 2011 and 2010 compared to March 31, 2011 and 2010, respectively, partially offset by high oil prices prevalent during the periods, we recorded a gain on oil derivatives of $34.5 million and $24.9 million during the second quarters of 2011 and 2010, respectively. This includes losses of $6.8 million and $8.6 reclassified into earnings during the second quarters of 2011 and 2010, respectively, which were associated with derivatives for which hedge accounting was previously discontinued.

During the second quarter of 2011, we recorded a gain on gas derivatives of $6.9 million, due primarily to low natural gas prices prevalent during the period. Due primarily to higher average NYMEX forward strip gas prices as of June 30, 2010 compared to March 31, 2010, partially offset by low natural gas prices prevalent during the period, we recognized a non-hedge loss on gas derivatives of $4.5 million during the second quarter of 2010. In addition, we reclassified into earnings gains of $0.3 million which were associated with derivatives for which hedge accounting was previously discontinued.

During the second quarter of 2011, the loss on natural gas basis differential contracts was $0.9 million, due primarily to low basis differentials prevalent during the period, partially offset by lower average contractual prices as of June 30, 2011 compared to March 31, 2011. Due primarily to lower average contractual prices and higher differentials indicated by the forward commodity price curves as of June 30, 2010 compared to March 31, 2010, partially offset by low basis differentials prevalent during the period, we recognized gains of $3.7 million for the second quarter of 2011.

During the second quarter of 2010, we unwound and monetized oil swaps and collars and natural gas collars with original settlement dates from April 2010 through December 2012 for net proceeds of $7.1 million, and we recognized a gain of $7.3 million associated with these transactions.

Primarily as a result of the above transactions, we recognized total gains on derivative activities of $40.5 and $31.7 million for the three months ended June 30, 2011 and 2010, respectively.

The effects of derivative activities on our results of operations and cash flows for the first half of 2011 and 2010 were as follows:


	Six months ended June 30,
	2011						2010
(dollars in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Loss from oil and natural gas hedging activities:
Oil swaps	$	(13,561	)	$	—		$	(8,551	)	$	(5,504	)
Natural gas swaps		—			—			864			—

Loss from oil and natural gas hedging activities	$	(13,561	)	$	—		$	(7,687	)	$	(5,504	)


Non-hedge derivative gains (losses):
Oil swaps and collars	$	16,163		$	(35,182	)	$	33,042		$	(815	)
Natural gas swaps and collars		(11,826	)		19,330			4,430			25,964
Natural gas basis differential contracts		1,939			(4,054	)		7,495			(6,489	)
Derivative monetizations		—			—			193			7,097

Non-hedge derivative gains (losses)	$	6,276		$	(19,906	)	$	45,160		$	25,757

Total gains (losses) from derivative activities	$	(7,285	)	$	(19,906	)	$	37,473		$	20,253

During the first half of 2011, we recorded a loss of $32.6 million on oil derivatives, primarily due to high oil prices prevalent during the period, partially offset by higher average contractual prices as of June 30, 2011 compared to December 31, 2010. This includes losses of $13.6 million reclassified into earnings during the first half of 2011 that were associated with derivatives for which hedge accounting was previously discontinued. Due primarily to a decrease in average NYMEX forward strip oil prices as of June 30, 2010 compared to December 31, 2009, we recognized a non-hedge gain on oil derivatives of $32.2 million during the first half of 2010. In addition, we reclassified into earnings an $8.6 million loss associated with oil derivatives for which hedge accounting has been discontinued, and we made payments on oil hedges of $5.5 million during the first six months of 2010.

During the first half of 2011, we recorded a gain on gas derivatives of $7.5 million, due primarily to low natural gas prices prevalent during the period, partially offset by lower average contractual prices and higher average NYMEX forward strip gas prices as of June 30, 2011 compared to December 30, 2010. Due primarily to high natural gas prices prevalent during the period, we recognized a non-hedge gain on gas derivatives of $30.4 million during the first half of 2010. In addition, we reclassified into earnings gains of $0.9 million which were associated with derivatives for which hedge accounting was previously discontinued.

During the first half of 2011, the loss on natural gas basis differential contracts was $2.1 million, due primarily to low basis differentials prevalent during the period, partially offset by lower average contractual prices as of June 30, 2011 compared to December 31, 2010. Due primarily to lower average contractual prices and higher differentials indicated by the forward commodity price curves as of June 30, 2010 compared to December 31, 2009, partially offset by low basis differentials prevalent during the period, we recognized a gain of $1.0 million for the first half of 2010.

During the first half of 2010, we unwound and monetized oil swaps and collars and natural gas collars with original settlement dates from April 2010 through December 2012 for net proceeds of $7.1 million, and we recognized a gain of $7.3 million associated with these transactions.

Primarily as a result of the above transactions, we recognized total losses on derivative activities of $27.2 million for the first half of 2011 and gains of $57.7 million for the first half of 2010.

Lease operating expenses


	Three months ended June 30,				Percentage change			Six months ended June 30,				Percentage change
	2011		2010		Percentage change			2011		2010		Percentage change
Lease operating expenses (in thousands)	$	31,748	$	27,256		16.5	%	$	59,304	$	51,675		14.8	%

Lease operating expenses per Boe	$	14.44	$	13.30		8.6	%	$	13.92	$	13.19		5.5	%

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices.

Our lease operating expenses increased by $4.5 million, or $1.14 per Boe, during the second quarter of 2011 compared to the second quarter of 2010, and $7.6 million, or $0.73 per Boe, during the first half of 2011 compared to the first half of 2010, primarily due to our increased activity combined with the upward pressure on operating and service costs associated with higher oil prices.

Production taxes (which include ad valorem taxes)


	Three months ended June 30,				Percentage change			Six months ended June 30,				Percentage change
	2011		2010		Percentage change			2011		2010		Percentage change
Production taxes (in thousands)	$	9,456	$	6,190		52.8	%	$	18,080	$	13,180		37.2	%

Production taxes per Boe	$	4.30	$	3.02		42.4	%	$	4.24	$	3.36		26.2	%

Production taxes generally change in proportion to oil and natural gas sales. The increase in production taxes during the second quarter of 2011 compared to the second quarter of 2010 was primarily due to the 41% increase in average realized prices combined with the 7% increase in sales volumes. The increase in production taxes during the first half of 2011 compared to the first half of 2010 was primarily due to the 28% increase in average realized prices combined with the 9% increase in sales volumes.

Depreciation, depletion and amortization (“DD&A”)


	Three months ended June 30,				Percentage change			Six months ended June 30				Percentage change
	2011		2010		Percentage change			2011		2010		Percentage change
DD&A (in thousands):
Oil and natural gas properties	$	33,398	$	21,956		52.1	%	$	63,933	$	43,449		47.1	%
Property and equipment		2,584		2,306		12.1	%		5,152		4,546		13.3	%
Accretion of asset retirement obligation		895		805		11.2	%		1,769		1,593		11.0	%

Total DD&A	$	36,877	$	25,067		47.1	%	$	70,854	$	49,588		42.9	%


DD&A per Boe:
Oil and natural gas properties	$	15.19	$	10.72		41.7	%	$	15.00	$	11.09		35.3	%
Other fixed assets		1.58		1.51		4.6	%		1.63		1.57		3.8	%

Total DD&A per Boe	$	16.77	$	12.23		37.1	%	$	16.63	$	12.66		31.4	%

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $11.4 million in the second quarter of 2011 compared to the second quarter of 2010, of which $9.8 million was due to a higher rate per equivalent unit of production and $1.6 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $4.47 to $15.19 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

DD&A on oil and natural gas properties increased $20.5 million in the first half of 2011 compared to the first half of 2010, of which $16.7 million was due to a higher rate per equivalent unit of production and $3.8 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $3.91 to $15.00 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

General and administrative expenses (“G&A”)


	Three months ended June 30						Percentage change			Six months ended June 30						Percentage change
(dollars in thousands, excluding per Boe amounts)	2011			2010			Percentage change			2011			2010			Percentage change
Gross G&A expenses	$	13,805		$	11,543			19.6	%	$	26,227		$	21,179			23.8	%
Capitalized exploration and development costs		(4,238	)		(3,672	)		15.4	%		(8,652	)		(6,868	)		26.0	%

Net G&A expenses	$	9,567		$	7,871			21.5	%	$	17,575		$	14,311			22.8	%

Average G&A cost per Boe	$	4.35		$	3.84			13.3	%	$	4.12		$	3.65			12.9	%

G&A expenses for the three and six months ended June 30, 2011 increased by $0.51 per Boe and $0.47 per Boe, respectively, compared to the three and six months ended June 30, 2010, primarily due to higher compensation costs caused by our heightened level of activity. G&A expenses for the three and six months ended June 30, 2011 include stock-based compensation expenses of $0.8 million and $1.8 million, respectively, of which $0.8 million and $1.6 million, respectively, are associated with grants of restricted stock under our 2010 Equity Incentive Plan that was adopted on April 12, 2010. G&A expenses for the three and six months ended June 30, 2010 include stock-based compensation expenses of $0.7 million and $0.8 million, respectively, of which $0.7 million are associated with initial grants of restricted stock under our 2010 Equity Incentive Plan.

Other income and expenses

Interest expense

The following table presents interest expense for the periods indicated:


	Three months ended June 30,						Six months ended June 30,
(dollars in thousands)	2011			2010			2011			2010
Revolver interest	$	—		$	2,118		$	—		$	8,773
8.5% Senior Notes due 2015		—			7,120			4,588			14,235
8.875% Senior Notes due 2017		7,436			7,416			14,867			14,827
9.875% Senior Notes due 2020		7,613			—			14,968			—
8.25% Senior Notes due 2021		8,381			—			11,826			—
Bank fees and other interest		1,370			1,249			2,877			3,008
Capitalized interest		(579	)		(369	)		(1,195	)		(757	)

Total interest expense	$	24,221		$	17,534		$	47,931		$	40,086

Average long-term borrowings	$	1,036,742		$	840,585		$	1,024,375		$	1,008,435

Total interest expense increased by $6.7 million during the second quarter of 2011 compared to the second quarter of 2010 primarily due to increased levels of borrowing combined with higher average interest rates. Total interest expense increased by $7.8 million during the first half of 2011 compared to the first half of 2010 primarily due to higher average interest rates.

Loss on extinguishment of debt. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the three and six months ended June 30, 2011, we recorded a loss associated with the refinancing of our 8.5% Senior Notes of $0 and $20.6 million, respectively.

On April 12, 2010, we entered into and closed an Eighth Restated Credit Agreement. We used the proceeds available under the Eighth Restated Credit Agreement to repay the amounts owing under our Seventh Restated Credit Agreement. During the three and six months ended June 30, 2010, we recorded a loss of $2.2 million related to the write off of prepaid bank fees associated with our Seventh Restated Credit Agreement.

Non-GAAP financial measure and reconciliation

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 is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

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) deferred compensation expense, (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual charges.

The following table provides a reconciliation of our net income to adjusted EBITDA for the specified periods:


	Three months ended June 30,						Six months ended June 30,
(dollars in thousands)	2011			2010			2011			2010
Net income	$	47,394		$	24,878		$	7,130		$	50,342
Interest expense		24,221			17,534			47,931			40,086
Income tax expense		28,010			16,340			5,851			32,409
Depreciation, depletion, and amortization		36,877			25,067			70,854			49,588
Unrealized loss on ineffective portion of hedges and reclassification adjustments		6,806			8,206			13,561			7,687
Non-cash change in fair value of non-hedge derivative instruments		(61,908	)		(31,257	)		(6,276	)		(54,578	)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from the monetization date included in EBITDA		—			9,418			—			9,418
Interest income		(17	)		(20	)		(82	)		(112	)
Deferred compensation expense		807			701			1,873			867
Gain on disposed assets		(54	)		(32	)		(49	)		(74	)
Loss on extinguishment of debt		—			2,241			20,576			2,241

Adjusted EBITDA	$	82,136		$	73,076		$	161,369		$	137,874

Critical accounting policies

For a discussion of our critical accounting policies, which remain unchanged, see Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2010.

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

Recent accounting pronouncements

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Oil and natural gas prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the first half of 2011, our gross revenues from oil and gas sales would change approximately $1.1 million for each $0.10 change in natural gas prices and $2.5 million for each $1.00 change in oil prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps. Effective April 1, 2010, we have elected to de-designate all of our commodity contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. Therefore, the changes in fair value and settlement of all our derivative contracts subsequent to March 31, 2010 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.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position.

Our outstanding oil and natural gas derivative instruments as of June 30, 2011, are summarized below:


	Oil derivatives
	Swaps				Collars				Three-way collars
											Weighted average fixed price per Bbl
	Volume MBbls		Weighted average fixed price per Bbl		Volume MBbls		Weighted average range (fixed price per Bbl)		Volume MBbls		Additional put option		Floor		Ceiling		Percent of PDP production (1)
3Q 2011		829	$	78.28		21	$	110.00 - $153.00		—	$	—	$	—	$	—		79.2	%
4Q 2011		777		76.83		21	$	110.00 - $153.00		—		—		—		—		79.8	%
1Q 2012		536		94.81		—		—		210		67.14		90.00		110.26		79.0	%
2Q 2012		504		94.17		—		—		210		67.14		90.00		110.26		79.1	%
3Q 2012		480		93.75		—		—		210		67.14		90.00		110.26		79.2	%
4Q 2012		463		93.50		—		—		210		67.14		90.00		110.26		79.6	%
1Q 2013		135		102.97		—		—		270		73.33		97.22		126.00		49.2	%
2Q 2013		135		102.52		—		—		270		73.33		97.22		126.00		50.4	%
3Q 2013		135		102.24		—		—		270		73.33		97.22		126.00		54.3	%
4Q 2013		135		102.05		—		—		270		73.33		97.22		126.00		55.7	%

		4,129				42				1,920


	Natural gas swaps							Natural gas basis protection swaps
	Volume BBtu		Weighted average fixed price per Btu		Percent of PDP production(1)			Volume BBtu		Weighted average fixed price per Btu
3Q 2011		4,960	$	6.07		77.0	%		3,720	$	0.64
4Q 2011		4,620		6.51		79.8	%		3,610		0.65
1Q 2012		3,000		5.11		56.0	%		2,100		0.30
2Q 2012		3,000		4.94		59.4	%		2,100		0.30
3Q 2012		3,000		5.01		62.3	%		2,100		0.30
4Q 2012		3,000		5.19		65.0	%		2,100		0.30
1Q 2013		1,800		5.34		40.5	%		—		—
2Q 2013		1,800		5.07		42.1	%		—		—
3Q 2013		1,800		5.16		45.4	%		—		—
4Q 2013		1,800		5.40		46.9	%		—		—

		28,780							15,730

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

Interest rates. There were no outstanding borrowings under our senior secured revolving facility as of June 30, 2011. We may designate borrowings under our senior secured revolving credit facility 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 senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in the senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO rate, as defined in our senior secured revolving credit facility, plus 1%. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $375.0 million, equal to our borrowing base at June 30, 2011, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.75 million.

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the period covered by this quarterly report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act 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. We may make changes in our internal control procedures from time to time.

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Naylor Farms, Inc. v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5.0 million. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied the allegations and are aggressively defending the case. The case is in the initial stages of discovery and has not yet been set for trial. As such, we are not yet able to estimate what impact, if any, the action will have on our financial condition, results of operations, or cash flows.

ITEM 1A.

RISK FACTORS

Due to recent actions at the federal level, we are updating and restating the following risk factor previously set forth in our 2010 Form 10-K:

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

The U.S. Congress has previously considered legislation to reduce emissions of greenhouse gases, including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. However, legislation to reduce greenhouse gases appears less likely in the near term. As a result, regulation of greenhouse gases, will continue to result primarily from regulatory action by the Environmental Protection Agency (EPA) or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

Federal regulation. EPA has adopted regulations requiring Clean Air Act (CAA) permitting of greenhouse gas emissions from stationary sources. As a result of the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA finding that greenhouse gases fall within the CAA’s definition of “air pollutant,” the EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases from motor vehicles may “cause or contribute” to this endangerment. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act”. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy. While these motor vehicle regulations do not directly impact oil and natural gas production operations, they automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emissions, potentially including oil and natural gas production operations. On June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO₂e”) for modifications and 100,000 tons per year CO₂e for new sources.

Additionally, EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This reporting rule became effective on December 29, 2009. On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.

Though under review by the D.C. Circuit, EPA’s rules promulgated thus far have survived petitions for stay, and thus are currently final and effective, and will remain so unless vacated or remanded by the court, or unless Congress adopts legislation preempting EPA’s regulatory authority to address greenhouse gases under the CAA.

International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 16th meeting of the Council of the Parties in Mexico in November and December 2010 did not produce a legally binding final agreement, international negotiations continue, with the participation of the United States.

International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for fossil fuels generally.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1A. of our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, financial condition, or future results.

ITEM 6.

EXHIBITS


Exhibit No.		Description

10.1*		Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Incorporated by reference

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 12, 2011

EXHIBIT INDEX


Exhibit No.		Description

10.1*		Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011 (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Incorporated by reference

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